The Spectrum of
New Business Relationships
Producers and contractors share one objective—to reduce the cost of doing business. To this end, oil companies are converging to fewer service suppliers and expecting more of them. Service companies are organizing
themselves to provide better service. A group of drilling, petroleum technology, completion and asset managers discusses how their companies are making these changes work to their advantage.
STEPHANE CHAFCOULOFF
Comoderator
Oil companies, whether majors, independents or state-owned, are
evaluating how best to use their resources to remain profitable.
Most have begun to outsource noncore activities. How does your
company view outsourcing?
DAVID BLACKWOOD
Stephane Chafcouloff
Comoderator
Montrouge, France
Roger Goodan
Comoderator
Houston, Texas, USA
BP considers itself, certainly in the North Sea, to have gone quite
far down the road of outsourcing. Four years ago, we took what
was seen as a fairly bold move in outsourcing our accounting
activities. It was the first major outsourcing, and not a technical
area, but it was thought at the time to be pretty close to a core
activity. It’s been very successful and challenged our thinking on
what is and isn’t a core activity. It also clarified the distinction
between accounting and management control.
STEVE DOLE
We’ve outsourced some of PanCanadian’s noncore activities in
facilities engineering and facilities construction, but we haven’t
outsourced drilling or completions. We’ve developed a strategic
alliance with Dowell for stimulation services. But that’s not outsourcing in the sense of delegating engineering to their side. While
we still maintain an engineering expertise, we can take advantage
of Dowell’s capabilities. We’ve removed duplication of effort in
our stimulation process—design, execution and evaluation.
FREDDY PÉREZ
At Lagoven, we’re working toward outsourcing all noncore activities, from well construction and maintenance, through logistics
and supporting services to facility design and construction. Reservoir management, even though a nondelegable core business
activity, is being supported by joint efforts with third parties,
including service companies. This is achieved through integrated
In this article, DESC (Design and Evaluation Services for Clients) is a mark
of Schlumberger.
4
Oilfield Review
Jerry Anderson
Mobil Oil Canada
Calgary, Alberta, Canada
David Blackwood
BP Exploration
Aberdeen, Scotland
Steve Dole
PanCanadian Petroleum Limited
Calgary, Alberta, Canada
Gavin Humphreys
Shell UK Exploration and
Production
Carl Lawson
Phillips Petroleum Company
Bartlesville, Oklahoma, USA
reservoir studies that result in better reservoir characterization,
from which optimum designs can be derived. With this approach,
we incorporate the best knowledge to identify the most efficient
economic means to use state-of-the-art technology and achieve
good operational capability.
CARL LAWSON
Freddy Pérez
Lagoven
Caracas, Venezuela
Summer 1995
Reservoir management is also sacred to Phillips, and we don’t outsource it. We do some outsourcing on the drilling side. In remote
locations, like Papua New Guinea and Cameroon, we are turning
a lot of our business over to the drilling contractors or the service
companies. In these areas, where we don’t have the infrastructure
to take care of the operation, we outsource it by forming an
alliance or giving an integrated service contract. Partnering is the
only way to complete a cost-effective operation. Our alliance in
Papua New Guinea was very successful. The well drilled before
the alliance cost $17 million. Under the alliance, we drilled the
next well for less than half that cost—$8.1 million.
We also work with integrated services packages, such as with
Halliburton for our offshore China operation. They picked the
5
service companies and the drilling contractor, and we supplied the
drilling supervisors on the rig who worked with a small engineering group on the mainland.
DAVID
At BP, our global organization is divided into 42 assets, with 40%
of them based in Aberdeen. Functionally, we have a very light
touch—we have a broad strategy but allow individual assets a fair
degree of autonomy. No two assets will necessarily act in exactly
the same way. If we look at early production schemes, in the classic role, the North Sea operator went to ten different service companies and tried to orchestrate them all—drilling, a rig-based vessel to house the production facilities, supply and operation of the
production facilities, and then export to a tanker. The Machar field
is an example of what success can look like—the project management was outlined by BP, but the project was essentially managed
outside the company.1 Other assets might not take that approach.
[For more on this project, see “Integrated Services,” page 11.]
Drawing an analogy with new field development, when anyone
wants to design a platform these days, in comes an engineering
company to do the whole thing. So, philosophically, everyone
crossed that outsourcing bridge years ago. In one asset, we’ve just
extended it to the other end of the life of the field by taking the
reservoir engineering out of the BP organization.
GAVIN HUMPHREYS
At Shell UK Exploration and Production [Expro] we have integrated drilling engineering, completions and well services into
well engineering organizations. Using a well engineering business
process model, we defined our core and noncore activities, then
developed a program to outsource noncore activity when this
makes business sense. We were then able to define our generic
organization and manning requirements.
In our model, we treat project management as a core business,
so within any outsourced projects we always retain a Shell well
engineer as the project manager reporting to a Shell head of well
engineering. The Expro model for the North Sea, and our definitions of core and noncore business, may not be appropriate to
other Shell operating companies, which may develop different
models on the same principles.
CARL
In remote locations, we specify in our bids that we want a project,
or logistics manager, who is usually a drilling contractor. In integrated services packages, I’d like to see service companies have
one individual taking care of all the product lines. If I’m working
with a number of people, and don’t have one entity I can contact,
I fall back on the traditional way of doing business.
FREDDY
At Lagoven, we do not completely outsource project management.
In cases where we have third parties performing specific tasks,
even with Lagoven personnel as part of the team, we currently
maintain leadership by means of a Lagoven project manager. For
special projects, such as exploration wells in the Orinoco
Delta—at around 20,000 ft [6100 m]—we create a special task
force for the engineering design. Then we bring the service companies and drilling contractors into the team so that a comprehensive review of the design can be carried out. This way, specific levels of know-how, technology and operational capability can be
put into place for designing and executing the most cost-effective
well construction plan.
ROGER GOODAN
Comoderator
There are many approaches to outsourced project
management—to name a few, drilling contractor, service company
and engineering company, meaning the company that builds platforms. What are the roles of these three in your projects, and
which usually has the position of lead contractor?
DAVID
We expect the service company to be the lead contractor, and to
bring along a drilling unit provider. The drilling services we’re
looking for include semisubmersible capability, jackups and
workover capability. We select a “best-in-class” contractor in each
category of required service. Very few people can do everything
for you, so some sort of group will come together—an integrated
services contractor or contracting alliance. Within the alliance
agreement the parties have worked up their share of the development cost—the actual cost of the project. Everyone knows the
6
Oilfield Review
GAVIN
Our lead contractors on our North Sea platforms are the drilling
contractors who have created alliances with our well services contractors. With our mobile rig fleet we have created a subsea
alliance that integrates the engineering effort of our lead drilling
and subsea completions contractors with our subsea equipment
manufacturers. In this environment, we provide to the alliance
contractors a conceptual design of our requirements, which they
translate into a detailed program to fulfill our objectives.
JERRY ANDERSON
On lead contractors, Mobil has not yet gone as far as Shell and BP.
We utilize a lead contractor in a coordination role, and select the
contractor based on what makes sense for that particular job. I
would agree with Carl—in a remote location, the drilling contractor is the most likely candidate, but in others it could be a service
company. We maintain ultimate control for approval of personnel
on our jobs and the contractor or service provider coordinates the
various services.
Along those lines, we also use turnkeys where they make good
business sense for Mobil. This past year we drilled an exploration
well in Egypt using a turnkey contract. We didn’t have a presence
in the country, but the turnkey contractor had an infrastructure set
up, and was able to meet the required timing. We also recently
turnkeyed a group of shallow wells in eastern Oklahoma. A local
contractor familiar with the area could do it cheaper and better
than we could. Generally speaking though, we find that on
deeper, higher pressure wells and remote wells, we can simply do
it for less money than a turnkey.
CARL
number, we set the target costs, and then everyone shares in the
gain and the pain of either getting above or below that target cost.
The project manager, whether from BP or a contractor, is dedicated for the life of the project. This approach works only if people
within the project management team can make commitments on
behalf of their organizations.
FREDDY
It is our view today that the people who are connected to the reservoir should be playing the major role, and leading for the future.
We see drilling the well as just another service, which should
respond to the reservoir needs. This could vary if the project were
divided into specific tasks; then the service of most value, and not
necessarily the most costly, should have the leading role.
CARL
For Phillips, that has already taken place in China, where we’ve
used the drilling contractor as an integral part of integrated services. The service company, as project manager, chose the drilling
contractor as part of the services they offered. We have also operated another way, with three groups—the drilling contractor, the
service companies and the operator—in a type of alliance. On single wells in remote locations, we use the drilling contractor as the
lead project or logistics manager—the one with the best local
knowledge. We want somebody who knows how to get the job
done in a country, how to work with the government officials, how
to get materials into the country quickly and from the warehouse
to the location.
Summer 1995
We have also found it difficult to get a turnkey contract for drilling
exploration wells in a remote location. Contractors are unwilling
to turnkey because the risk is too high, or they have to put such a
large risk factor into the contract that the cost would be unreasonable. We tried to bid a Cameroon well out as a turnkey operation
but no one was willing to take the risk. The Gulf of Mexico and
onshore US are areas where we have used turnkeys.
GAVIN
I believe that to optimize turnkeys, the well engineering contractor
needs to be able to produce the same product continually, and so
learn and make money over the full project. Shell recently
turnkeyed more than 120 similar wells in Oman very successfully.
In Expro, however, we do not often have this environment. Technology continues to develop—with more horizontal and multilateral wells—and as such we are unable to clearly define to our
contractors our requirements, which they use to estimate a cost.
Turnkey in this environment is simply unfair and in contradiction
to the win-win environment we advocate.
1. For other outsourcing by BP:
Cross J: “IT Outsourcing: British Petroleum’s Competitive Approach,” Harvard Business Review (May-June 1995): 94-102.
7
STEPHANE
I’d like to shift gears here, and focus on one of the newer roles of
service company people. Placement of service company people
in the operating company office has been a growing trend—a
prime example is the rapid growth in Dowell’s DESC program.
[For a review of the DESC Design and Evaluation Services for
Clients program, see “The DESC Engineer Redefines Work,” page
40.] What do you think about service company personnel posted
in your organization?
STEVE
We feel strongly that it affords us tangible and significant benefits.
Three Dowell engineers have been working in PanCanadian for
almost four years. By now, these fellows fit right into our organization—they’re part of the completions team. They’re involved in our
project planning, design and execution, and having them across
the hall from our engineers helps us move through the designredesign iteration quickly and effectively. We have empowered
them to act as efficiently as possible, which streamlines decision
making. If they decide something needs to be done, there’s not a
lot of negotiating.
Having those folks in our office also helps us see how Dowell
works, and helps Dowell focus on the reservoir rather than on
horsepower or volume of fluid pumped. Our mutual goal is to
extract hydrocarbons as cheaply as possible, and dollars per barrel
of oil is what we’re both targeting. By focusing on the reservoir, we
can work toward that goal. That’s the biggest benefit—getting
everyone focused on that common objective. However, what ultimately makes it work is having the right people—people who can
fit into the organization. In the early stages there was some work to
develop the required trust, but once we got by that, it’s been
onward and upward.
STEPHANE
The Dowell engineers focus mainly on completion engineering.
How important would it be to have the expertise to develop the
well from A to Z?
STEVE
Today we’re looking for specific technical expertise. But at the same
time, we want a link to the broader picture so that we can identify
the advantages in using other kinds of contractor expertise. For us,
this is another benefit of having DESC engineers on board: they
give us access to other parts of the Schlumberger organization. For
example, our DESC engineers tapped into other Schlumberger people to help us with a completion design for a zone that neither PanCanadian nor other operators had been able to complete successfully. A team of our people and Schlumberger people succeeded in
getting commercial production out of that zone.
FREDDY
We can make the best use of service company expertise if the engineer works closely with our people, whether in our office or in the
service company office. We want the service company to understand our reservoirs, and one way to do that is to get into our office,
dig into the files and identify ways to improve our productivity.
This comes about as a result of a joint diagnostic study of the
well from which specific services are designed and evaluated economically. Close interaction and effective communication
between the parties make approvals more efficient.
JERRY
Mobil makes effective use of service company engineers in our
offices. We have offices for service company engineers, they are
hooked up to our e-mail system and network, they attend our
meetings and interact with our reservoir management teams as
participating members, just like Mobil employees. We have a
number of service company engineers in place, in particular, pressure pumping engineers and some well performance people in our
drilling groups. This is one form of outsourcing in which we utilize
service company people to do things that they do well. This frees
our people to work on things that are of higher value to us and
that they are best suited to do.
GAVIN
In Shell Expro, we also have all our lead contractors networked
into our main well-engineering data base, and in some cases Shell
senior well engineers move into the lead contractor’s office to
head the project from there. Where we have developed quality
improvement projects, our contractors and our lead contractor’s
subcontractors are involved in the quality management process
since we value their contribution to the well engineering.
I’m not against the principle of contractor and Shell Expro staff
interchanging their respective roles. There is value in everyone
understanding better what everyone else does.
STEPHANE
We’ve talked about many forms of outsourcing, such as turnkeys,
integrated services, alliances and service company engineers in
the oil company office. Does your company have a model for
these new types of contractor-operator relationships?
Our mutual goal is to
extract hydrocarbons as
cheaply as possible…
By focusing on the
reservoir, we can work
toward that goal.
—Steve Dole
FREDDY
At Lagoven we have experienced and analyzed different relationships, and from a technology capture point of view, we believe
that the fastest way to transfer technology is to let technology users
pull it in from technology providers. Incentive contracts focus
everyone’s effort on doing just that by instilling a culture of working together. This allows better use of standard technology and
faster adaptation of new technology—not for the sake of fast technology transfer, but because the partnership knows it makes good
business sense.
DAVID
There are many models for partnerships, but they can collapse to
look like one. We try not to limit our possibilities with language.
The issue is the alignment of the objectives on both sides. In the
simplest of terms, we both make our money the same way.
8
Oilfield Review
JERRY
At Mobil we see a spectrum of business relationships ranging from
the traditional day-work model all the way to turnkey. Between
these extremes are many other options, including strategic
alliances, integrated services and incentive contracts. We prefer to
call these Enhanced Supplier Relationships, or ESRs. We encourage our drilling people worldwide to do what makes sense for
their local operation. Our approach is to maximize the net present
value of our wellbore assets. Driving down cost may be the biggest
factor, and that’s what we’re doing with ESRs. We are using them
in some form all over the world.
To date, we’ve had the most success with the strategic alliance,
working with our service providers to drive down total costs and
sharing in the savings. [For more on alliances, see “Alliances in the
Oil Field,” page 26.] We are beginning to expand these into integrated services, allied multiple services. We have also had success
in the integrated services approach by putting together the drilling
contractor and one or more service companies, appointing a lead,
then optimizing from that standpoint.
CARL
I agree that no single operator can to do all the R&D. Amoco’s
drilling R&D department has talked with Phillips and Conoco
about an alliance in which we will share their facility to do
research and development, and share the cost. I’m in favor of
keeping R&D alive, and this may be a way of doing that.
JERRY
Much of what the drilling R&D group does in Mobil is technical
service work. We do very little pure research and development
anymore, but when we do, it is in conjunction with the major
service companies. We don’t worry much about confidentiality.
We recognize that we have to work jointly if we’re going to
accomplish anything worthwhile. Unless it’s something particularly confidential to Mobil, we are glad to work with the major
service companies.
…we believe the fastest
way to transfer
technology is to let
technology users pull it
in from technology
providers.
GAVIN
I have a bit of a problem differentiating between integrated services and strategic alliances. You should do what’s most appropriate for the business. You shouldn’t use a model that prevents you
from maintaining flexibility in relationships with your lead contractors and the service industry.
—Freddy Pérez
JERRY
We’ve talked here about the relationship between the operator
and the service company, but what we have found in developing
ESRs, in strategic alliances in particular, is that the internal partnering within our own company is equally or even more important
than partnering between the operator and service company. When
we map our processes and then overlay those with the processes
of our service company—with the goal of driving out waste—we
often find most of that waste within our own company. Removing
this waste requires involvement of all the contributing departments
within the operating company as well as the service company.
GAVIN
I support Jerry’s view. If we can’t involve all members of our oil
company community who contribute to the well engineering process, we will fail. We need complete commitment from the
petroleum engineering, contract and procurement people to realize
the full savings potential of a well engineering business process.
ROGER
For Schlumberger, the most active areas for alliances and integrated services are North America and the North Sea. Only in the
last year has the trend reached West Africa and just now is extending to the Far East. This global expansion raises a key question:
Can service companies and operators also expand the scope of
their work together to include research, shared technology or intellectual rights? Is confidentiality a problem?
FREDDY
Petroleos de Venezuela (PDVSA) affiliates have a research and
development institution—Intevep—that provides services for the
oil and gas industry. This institution has several areas of activities.
In addition to R&D, there are technical services, which assist operators in evaluating, procuring and adopting existing technology, as
well as developing differentiating technology for our business
needs. However, joint R&D projects have been developed with
other operators, universities and service companies. The funding of
these projects is mutually agreed upon, and varies with the scope
and expected results. Confidentiality is not a problem, but a matter
of understanding upon which there must also be agreement.
GAVIN
There has to be continued dialogue between the innovators, the
technologists and the clients in the oil companies. On the issue of
funding, no single oil company can fund this research and development on its own, so some of these new projects need a joint
approach. Our drilling R&D laboratory in Rijswijk, The Netherlands, already works with our operating companies, the service
industry and with other operators in Joint Industry
Projects—JIPs—whenever there is a business need to do so.
Summer 1995
9
STEVE
GAVIN
We don’t have an R&D organization within PanCanadian but we
do have an R&D budget to support various initiatives through
research groups around the world. Through our operations alliance
with Dowell in Canada, we’re essentially supporting the Dowell
research group in the States. This has allowed us to influence and,
in some cases, even direct some of the research done at the Dowell center in Tulsa—for example, the development of breakers to
meet our specific needs.2 If we see a need for something that is
bigger than what our share would support, we’ll reevaluate our
corporate R&D budget and work with Dowell to address specific
projects. We haven’t been concerned with confidentiality.
ROGER
We’ve seen that the evolving relationship between operators and
contractors has got to be a win-win situation for both parties.
What kind of relationship with the service companies do you want
in the future?
The issue is the
alignment of the
objectives on both sides.
In the simplest of terms,
we both make our
money the same way.
—David Blackwood
In the North Sea, the focus must be on long-term reduction of well
cost in terms of £/bbl, that is, life cycle cost. The way we do business in the future depends on enhanced technologies, which are
channeled from the operators, service companies and smaller
niche companies into the industry. Shell will maintain a close relationship with technology-focused companies, as we see continued
value of their contribution to well design, one Shell core business.
FREDDY
A trusting relationship allows the service company to appreciate
its impact on the business, and speeds the development of a winwin relationship between the two parties. Our relationships with
service companies are unique. We view these relationships as a
prime source of technology, knowledge and operational capability.
They allow not only cost reduction, but also increased productivity
and the generation of more work.
CARL
What I’d like to see continue from the contractors and service
companies is honest and open communication. They have a lot of
good ideas and have been talking about alliances since 1992. But
in remote locations in the Far East and Africa, the concepts of integrated services and alliances have not reached the field workers.
We need to train field personnel so they understand how to work
in these kinds of teams.
JERRY
We’ve seen tremendous evolution in the last two years, but I’d like
to see the service companies be more proactive in telling us what
works with other clients. Rather than reinventing the wheel, I’d like
to know what has worked elsewhere and determine whether these
ideas could also apply to our business.
As we progress in these relationships, the biggest obstacle to
improvement is ourselves. Our cooperative efforts enjoy strong
support at the top. But for these relationships to work, and work
well, we need to have buy-in from bottom to top and all across the
various levels of the company.
STEVE
I agree with the argument for a company-wide buy-in. Learning
from the experiences of other alliances is also good advice. We’ve
explored sponsoring a conference with Dowell and other operators in North America engaged in pumping alliances, to talk about
what they’ve experienced, how alliances are built, what’s working
well, how results are measured and the future of alliances.
DAVID
I would like to see more open conversation on economics, and
how future investments can be influenced by everyone around the
table. The ideal relationship will be probably be longer term, more
stable, and less confrontational. Long-term stability should not be
confused with complacency, but rather a level of comfort with
working in an alliance—where all parties receive an appropriate
return on what they have put at stake, and where exceptional performance is rewarded.
—LS
2. Breakers are chemical agents added to fracturing fluid to allow easy cleanup of the
fracture after treatment.
10
Oilfield Review
Integrated Services
Oil and gas exploration and production provide greater challenges each year. These challenges are not just
technical, but involve the whole business process of drilling, completing and maintaining wells. To meet
them, oil companies are finding new ways of working with the service industry. One such relationship—integrated services—ranges from coordinating the execution of only a few services to fully designing and managing complete, complex projects.
Gavin Clark
Charlie Cosad
Kevin Forbes
Aberdeen, Scotland
Alliances
Flexibility in
adapting to
oil company
requirements
Contractor
Stephane Chafcouloff
Gilles Michel
Mike Trice
Montrouge, France
Integrated Services
Performance guarantees/quality control
Standard service
Oil Company
Supervise,
coordinate
many specialists
Oil
Company
Manage fewer
contractors for
quality assurance
■ Evolving roles of operating and service companies. Traditional
operator-contractor relations required the oil company to supervise
and coordinate many specialist services. Now oil companies are
focusing on their core business and managing fewer contractors.
Contractors are becoming more flexible in adapting to oil company requirements. This is leading to new business relationships,
such as integrated services and alliances.
For help in preparation of this article, thanks to Adriano
Bastos, Lance Davis, Tom O’Gallagher, Willie Richie
and Graham Ritchie, Schlumberger Wireline & Testing,
Aberdeen, Scotland; Richard Downey and Olivier
Lietard, Dowell, Aberdeen; Nancy Sayer, Sedco Forex,
Montrouge, France; Gerald Smith, Schlumberger Integrated Project Management, Aberdeen; Jon Turnbull,
BP ETAP group, Aberdeen; and Mike Unsworth, Sedco
Forex, Aberdeen.
In this article, ClientLink, DESIGN-EXECUTE-EVALUATE
(D-E-E) and PowerPak are marks of Schlumberger.
Following the boom and bust of the 1970s
and 1980s, the oil industry is now experiencing relatively stable oil prices. However,
during this period of more predictable revenues, exploration and production (E&P)
costs continue to rise, squeezing margins
and diminishing return on investment (ROI).
To stay profitable, many oil companies are
rethinking their business strategies and critically examining their relationships with the
service industry (above).
Nowhere is this more apparent than in the
North Sea. Development costs in the UK
may be up to six times greater per barrel of
oil than those of the US Gulf of Mexico or
the Pacific Rim. With more attractive markets opening in the former Soviet Union and
the Far East, oil companies have to reduce
costs and improve profitability in their
North Sea operations.
One major drive to reduce infrastructure
costs was initiated in 1992 by the UK Offshore Operators Association. It brings
together contractors, manufacturers and
service companies to develop CRINE—Cost
Reduction Initiative for the New Era. The
aims of CRINE are to decrease E&P capital
expenditures by up to 30% and operating
costs by up to 50%. CRINE is producing
results in the construction sector by encour-
11
UK Operating Costs by Field Vintage
£/barrel of oil equivalent, real terms
5
4
3
2
1
1985
1987
1989
1991
1993
1995
1997
All UK oil fields
Fields under development
1992 Fields in production
New starts 1993-1994
1999
■ Impact of CRINE on operating costs. For UK continental shelf oil fields in production
before the CRINE initiative in 1992, operating costs are expected to rise in the coming
years as older fields require more maintenance. Fields coming on stream in 1993 and
1994—after CRINE—show significantly lower operating costs. However, these costs are
also expected to increase as fields age. Fields currently under development are seeing
the full benefit of CRINE and other cost-saving initiatives such as integrated services.
These fields are expected to have the lowest operating costs, and the costs are not
expected to rise in the long term. (Courtesy of Wood Mackenzie.)
Traditional
Oil company
Integrated Services
Alliances
Oil company
Oil company
Integrated
group
Product line
Product line
PL
PL
TP
TP
■ Three kinds of operator-contractor relationships. In a traditional relationship, a service company supplies a product or
service to the oil company (left). An alliance is a long-term relationship between oil company and service company (center).
There is close cooperation between the two to develop longterm shared objectives. An integrated services contract combines expertise from several product lines (PL) and third parties
(TP) to work as a team on one project (right). Overseeing the
team is a project manager who reports to the oil company. Success in any of these relationships means keeping a strong link
between the oil and service companies and ensuring access to
optimal technology.
12
aging teamwork, and standardizing and simplifying designs where possible (left ).1
At the same time, oil companies are seeking similar savings in the service sector,
where drilling costs represent up to 60% of
project costs.2 The need to realize such savings has brought about a radical rethink of
the operator-contractor relationship.
Traditionally, oil companies designed,
engineered and planned exploration wells
and field developments. The service sector
was there solely to provide what was
requested, as quickly and cheaply as possible. For their part, service companies were
not directly involved in the objectives of oil
company projects. Price lists, day rates and
discounts littered every contract. The objectives of the two industry sectors were seldom in line.3
It is this misalignment of objectives that
the industry has set about changing. The aim
is to create new, more open and trusting
relationships between both parties. Oil companies are teaming up with service companies to utilize the strengths and knowledge
of all concerned to design and implement
more cost-effective field developments.
This process has yielded many initiatives,
one of which is integrated services (IS)—the
packaging of various services or products
under a single contract (left ).
Many tasks and services have been integrated to a limited extent for many years. A
classic example is well testing (see “Integration in Well Testing Services,” next page).
Recently, the drive toward new business
relationships has fostered farther-reaching
levels of integration.
For oil companies, IS contracts are normally project-specific, leaving fewer contractors to deal with. They are designed to
improve resource utilization, integrate technical solutions, reduce risk and deliver better quality and health, safety and environmental performance.
In some cases, long-term relationships not
linked to specific projects have developed,
1. Knott D: “Operators Target UK Cost Cuts,” Oil & Gas
Journal 91 (December 20, 1993): 31.
North Sea Report no. 262 by Wood Mackenzie, Edinburgh, Scotland, February 1995.
2. Robins KB and Roberts JD: “Operator/Contractor Teamwork is the Key to Performance Improvement,” paper
SPE/IADC 29333, presented at the 1995 SPE/IADC
Drilling Conference, Amsterdam, The Netherlands,
February 28-March 2, 1995.
Kamath RR and Liker JK: “A Second Look at Japanese
Product Development,” Harvard Business Review
(November-December 1994): 154-165.
3. Krahn DR: “Power and Quality: Two Approaches to
Service Company Support for the North Sea Oil Industry,” paper SPE/IADC 25741, presented at the SPE/IADC
Drilling Conference, Amsterdam, The Netherlands,
February 23-25, 1993.
Integration in Well Testing Services
Surface well test
Tubing-conveyed
perforating
Shut in build up
Flow period draw down
Rig up (R/U) & test
Make up & RIH
Make up
Drillstem test
5
R/D
2
R/D
Run-in-hole (RIH)
Tubulars
Rig down
2
POOH
2
RIH
Subsea valve assembly
R/U
Data acquisition
Bottomhole sample (BHS)
2
BHS
1
Surface sample
Sampling
Validation
Data interpretation
Downhole recorder
Make up
Surface readout
Make up
0
10
Preparation
Validation
1
1
Surface readout
20
30
Start test
Build up
40
50
2
60
Time, days
One of the most comprehensive packaging of
of equipment and a crew trained to handle both
tasks is seen in well testing. Services ranging
operations can reduce this number to two.
from perforating to running tubulars, from pro-
2
Rig Down (R/D)
Fire guns
Slick
2
Once this streamlined crew has rigged up the
duction logging to surface data acquisition could
TCP guns, they rig up the DST string. For the oil
■ Typical activity for
selected services during
a well test. The number
of people required for
each service is shown
on the right. This number may be reduced by
multiskilling—training
personnel to perform
several tasks. This
allows them to do additional tasks during otherwise idle periods. An
integrated well test
package, with a multiskilled work force, typically reduces the number of people required
by 30%.
70
Finish test
Number of
people
involved
since the early 1980s. And, to ensure compatibility,
DST and TCP product development is performed at a
single location in Rosharon, Texas, USA.
Integration of services has also led to design
be performed by many individuals from separate
company, having one service company perform
standardization in other areas of well testing. Pro-
service companies. In a typical example (above)
both tasks has three advantages. First, the crew
duction logging tool strings now incorporate sophis-
these tasks—if performed separately— require
knows how to set up and operate both sets of
ticated pressure gauges, allowing pressure tran-
22 people. Integration reduces this number to 15.
equipment, so that they won’t interfere with each
sient analysis during production logging runs. The
Consider two specific tasks—tubing-conveyed
other—vital in an operation dealing with explo-
latest gauge systems may be mounted on different
perforating (TCP) and drillstem testing (DST). A
sives and high pressure. Second, there is a
conveying systems that allow better utilization and
typical TCP job requires two people to prepare
reduction in personnel on board, saving costs on
greater flexibility in well test design.1
and hook up a length of TCP guns—usually with
transportation, accommodation and insurance.
help from the rig crew. Similarly, running a DST
Third, there is a single company to deal with,
string also requires two operators. Often TCP
easing communication and simplifying logistics.
guns are run below the DST string. If separate
Similarly, well testing crews are trained to
companies are involved, then four people are
handle several services; when they are not work-
required. A service company providing both sets
ing on one task they can be assigned to another.
1. For another example of how integration develops new
methods:
Murch DK, White DB, Prouvost LP, Michel GL and Ford
DH: “Integrated Automation for a Mud System,” paper
IADC/SPE 27447, presented at the IADC/SPE Drilling Conference, Dallas, Texas, USA, February 15-18, 1994.
Coordinating groups of services is the simplest
form of integrated services and is not new to the
service industry. Schlumberger Wireline & Testing has run combined DST and TCP services
13
like partnerships or alliances (see “Alliances
in the Oil Field,” page 26). These are deepening and broadening the degree of cooperation between oil and service companies.
nDrilling process.
The traditional
drilling process
consists of many
individual tasks,
each with narrow
workscopes
directly controlled
by the oil company. The interfaces between
each task are
potential sources of
additional cost and
waste (top). Rather
than contracting
for each task independently, the oil
company may
elect to bundle
tasks and contract
for fewer integrated services
with larger
workscopes and
fewer interfaces
(bottom).
Traditional Drilling Process
Oil company
First Steps Toward a New Relationship
14
Many individual tasks
Individual task
Narrow workscopes
Responsibility
interface
Many interfaces
Integrated Drilling Process
Oil company
Bundles
Bundles
Fewer interfaces
Individual task
Broader workscopes
Responsibility
interface
Business Process
Different oil companies
Seismic model
Geological structural model
Exploration appraisal
Possible
outsourcing
Geology
Petrophysics
Sedimentology
Reservoir management
A
B
C
Core business
Oil company
Reservoir simulation
Field development program
Production technology
Conceptual design
Economics
Life-cycle cost
Well engineering
Drilling
Completion
Well services
Operations
Engineering
Program planning
Contractor
Detailed programming
Operations management
Logistics planning
Program execution
nCore business. The minimum activities of an oil company’s
core business typically comprise seismic and structural modeling and exploration appraisal. Other activities, such as
detailed programming and program execution, are often considered noncore activities and are outsourced to the service
industry. The remaining activities are possible candidates for
outsourcing and may be classified as core activities by one oil
company and noncore by another. For example, oil company
A has defined its core business to include many more activities
than companies B and C.
Noncore business
In the past, oil companies performed many
tasks in-house that have since, by and large,
been outsourced. These included owning
drilling rigs and seismic vessels and employing the crews necessary to operate them.
Many other tasks, such as well construction, remained within the domain of the oil
companies: they decided on the concept,
made the plan and organized its execution.
Service companies performed the various
tasks in the plan separately, but under close
day-to-day supervision from oil company
personnel (right).
Examples from two operating companies
illustrate the changes that have evolved in
this relationship over the past few years.
In 1989, Shell Internationale Petroleum
Maatschappij B.V. (SIPM) introduced a drive
for increased operator efficiency with its
“Drilling in the Nineties” initiative.4 This
critically examined drilling activities and
concluded that many tasks, peripheral to
drilling, absorb much oil company time and
expense and should be delegated to contractors, permitting the oil company more
emphasis on core businesses.
A related issue is the single scope of work,
day-rate contract for rigs—very common
throughout the industry—that requires the
oil company to supervise the drilling contractor. The quality of this supervision of
personnel, equipment and materials provided by the contractor, to a large extent,
determines the quality of the work. It is in
the oil company’s interest to ensure the
fastest possible drilling rates. However, the
drilling contractor has little incentive to do
so, resulting in a basic conflict of interest
between the two parties. Replacing day-rate
contracts with incentive contracts gives contractors responsibility and involvement and
a structure for shared risks and rewards.
Incentive contracts include a multifunctional scope of work and require the contractor to become involved in planning,
optimization and managing intervention.
The incentive is designed to align the contractor’s goals with those of the oil company
by measuring performance during drilling
against key goals. Quality of the end product—the well—is ensured by establishing
criteria that allow acceptance or rejection of
the well.
Oilfield Review
In 1993, Shell UK Exploration and Production (Shell Expro) extended the concept
of incentive contracts to cover drilling, well
services and equipment supply areas. 5
“Well Engineering in the Nineties” (Win
90’s) again focused on core business and
performance-based contracts, but also
encouraged lasting and mutually beneficial
operator-contractor partnerships designed to
achieve continuous quality improvement
(previous page, bottom).
This introduces several key issues common to integrated services, including project evaluation. The ultimate goals of the
evaluation are to improve performance,
reduce costs and measure results against
expectations (below).
Other oil companies have been instrumental in this process and have developed
additional proactive approaches. Starting in
the UK, BP, for example, has implemented a
new operating philosophy based on the following fundamentals:
• align oil and service company goals
through performance-based contracts
• better utilize contractor expertise by minimizing duplicated effort of oil and service
companies, and clearly define roles and
responsibilities
• encourage teamwork, with teams composed of oil company, contractor and subcontractor personnel, to develop open
and trusting relationships
• implement continuous performance
improvement by committing to quality
management principles
• introduce long-term contractual security,
allowing commitment to organization and
performance targets.
To increase the participation from service
companies, BP decided to split well operations into three major business components:
well construction, well management and
data acquisition. Each component has substantial overlap, but each has different value
drivers (see “Vocabulary for New Business
Relationships,” page 17 ). For example, well
construction—the process of drilling and
completing new wells—is driven by speed
and quality of construction, keeping in mind
the ultimate objective of delivering a productive well.
By focusing on these major components,
BP encourages contractors to group com-
Traditional
Operator
mon services.6 Thus, integrated drilling services—one component of well construction—consists of directional drilling, measurements-while-drilling (MWD) and
logging while drilling (LWD), drilling fluids
and cementing, testing, mud logging, bits
and coring. These services form one contract. Another contract covers drilling rig
operations and associated services such as
casing crews, while a third covers data
acquisition (next page, middle ). A specific
example of an integrated drilling services
project is BP Exploration’s Wytch Farm
development on the south coast of England.
4. De Wardt JP: “Drilling Contracting in the Nineties,”
paper IADC/SPE 19902, presented at the IADC/SPE
Drilling Conference, Houston, Texas, USA, February
27–March 2, 1990.
5. “The Win 90’s Handbook—A Guide to the Strategy,”
Shell UK Exploration and Production, Win 90’s Project
Group, February 1994.
Shell Expro operates in the UK sector of the North Sea
on behalf of Shell Expro UK Ltd., Esso Exploration and
Production UK Ltd. and other coventurers.
6. Robins and Roberts, reference 2.
Nims DG, Doig MJ and Townhill R: “BP’s Well Construction Strategy—A Way Forward?” paper IADC/SPE
27457, presented at the IADC/SPE Drilling Conference,
Dallas, Texas, USA, February 15-18, 1994.
With Integration
Subcontractor
Approve
shipment
Operator
Supply
Issue order
Fax
details
Allocate
boat space
Call for
delivery
Prepare
shipment
Pack
FAX
containers
details
Operator
Transport
Load
truck
Send
transport
Transfer to
supply base
Inspect
lifting gear
Transfer
to dock
Drilling
Contractor
Subcontractor
Operator
Transport
Approve
shipment
Fax
details
Allocate
boat space
Prepare
and pack
Call for
delivery
Pack
containers
Inspect
lifting gear
Load boat,
then ship
nReducing administration. With integrated services, logistics are simplified for
offshore material loading.
Load boat,
then ship
Summer 1995
15
To reach the offshore part of the Sherwood Triassic reservoir at Wytch Farm, BP
had considered building an artificial island.
However, investigations indicated that
extended-reach drilling (ERD) from onshore
wellsites would cut capital costs and have a
lower impact on this environmentally sensitive region. In addition, the wells would
come on stream three years earlier.7
In 1992, BP contracted Anadrill to drill
some of the world’s longest ERD wells as
part of this development. Through close
cooperation, a clear definition of issues and
needs, and the application of innovative
technology, highly successful results were
obtained.
The first ERD well had a measured depth
of 14,600 ft [4450 m] with a stepout of
Integrated Well Construction
Oil company
Drilling operations
Rig
Logistics
Casing running
Fishing/milling
Drilling tools
Integrated drilling
services
Directional drilling
MWD/LWD
Drilling fluids
Cementing
Testing
Mud logging
Bits/Coring
Data acquisition
Logging
Data services
Integrated Well Management
Oil company
Drilling/workover
operations
Integrated well
services
Rig
Logistics
Casing running
Fishing/Milling
Drilling tools
Completion services
Slickline
Coiled tubing
Completion fluids
Cementing
Stimulation
Testing
Data acquisition
Logging
Data services
The Schlumberger Business Profile
•• Remain an independent service company with consistent business
relationship with all clients
•• Not an oil company; should not work for any organization lacking
geoscience expertise
•• Avoid any activity that competes with core businesses of our clients;
no conflict of interest
•• No joint ventures; no direct financing; no equity stake in client business
•• Payment for services in convertible currency; modulated by performance
incentives only when applicable
•• Welcome joint research projects with oil companies
16
nIntegrated models for well construction and well
management. The
integrated wellconstruction model
(top) bundles services into three
integrated teams:
drilling operations,
integrated drilling
services and data
acquisition. Similarly, the integrated well management model
(bottom) comprises
three groups:
workover operations, integrated
well services and
data acquisition.
These models are
tailored to fit project requirements.
12,655 ft [3857 m]. ERD operations on this
scale require intense engineering focus on
monitoring and analysis of field data. Daily
collaboration among a team of specialists
from BP, Anadrill and other service companies was vital.
The team’s success is shown by the
improved drilling performance from one
well to the next. Assessment of torque and
drag data from the first well showed that
lowering build rates would result in fewer
hole problems. This led to a single drilling
run of more than 5250 ft [1600 m] with a
PowerPak steerable motor. Further fine-tuning increased this distance to 7550 ft [2300
m] for a single run on the third well, with
total depth reached six days ahead of schedule. And in the fourth well, there was a
world-record run of 11,224 ft [3420 m].8
This improvement continues today with
another world record for a 12 1/4-in. bit run
of 13,169 ft [4014 m] on the latest well.
Learning has been fast. A well can now be
drilled in only half the time it used to take.
Including completion time, more than 50
days per well are being saved through teamwork and advanced technology, creating
added value and leading to considerable
cost savings for BP.
These examples from Shell and BP are just
a sampling of the changes sweeping the
industry. Other oil companies are striving
for different levels of integration. The concepts, initially applied in the UK sector of
the North Sea, are spreading rapidly worldwide to areas such as South America, West
Africa and the Far East.
Schlumberger Position
For the service industry, responding effectively to customer needs is all-important.9
Because oil companies have different ideas
on how they want to organize projects, the
service industry must remain flexible in its
approach, understanding the diverse
requirements of its clients (left ).
The Schlumberger strategy is to maintain
independent product lines, but draw on their
individual technical strengths through the
Integrated Project Management Group. This
7. Hazell MW and Cocking DA: “The Wytch Farm
Extended Reach Drilling Project,” presented at the 6th
International World Oil Horizontal Well Technology
Conference, Houston, Texas, USA, November 9-11,
1993.
8. Payne ML, Cocking DA and Hatch AJ: “Critical Technologies for Success in Extended Reach Drilling,”
paper SPE 28293, presented at the SPE Annual Technical Conference and Exhibition, New Orleans,
Louisiana, USA, September 25-28, 1994.
9. “Pressed into Service,” Journal of Petroleum Technology 46 (March 1994): 198-200, 223.
Oilfield Review
Vocabulary for New Business Relationships
Definitions of the terms below are not unique, but these are common interpretations of what they mean.
Alliance—A long-term relationship between two
Fast-track—Fast-track drilling occurs when
companies that furthers their common interests
wells are drilled, completed and put on stream
includes planning, executing, monitoring and
over a specific range of activities.
quickly. This enables early pay-back of costs.
reviewing the process. For example, to drill a
Beat-the-curve—A common incentive driver for
Fit-for-purpose—A piece of equipment that has
Process management—Process management
well involves conceptual design, detailed plan-
drilling is to complete a well in less time than
the qualities that match the requirements is said
ning, executing the plan, and monitoring and
planned. The plan usually takes the form of a
to be fit-for-purpose.
evaluating the results. How, when and where all
time-depth curve—hence beat-the-curve incen-
Insourcing—This practice makes better use of
these elements fit together forms the process.
tives. (This type of incentive relies on an accu-
internal resources by “contracting” internally
rate and mutually agreed-upon plan that identi-
work that used to be contracted to an outside sup-
company with an emphasis on changing the busi-
fies and addresses all relevant contingencies.)
plier. The opposite of outsourcing.
ness processes and increasing efficiency.
Reengineering—The process of reorganizing a
Benchmarks—These are the industry stan-
Lean drilling—A concept developed from lean
dards. Incentive contracts may be set against
production often used in the automobile industry.
dinating and supervising service company and
benchmarks. For example, Arthur D. Little, Lon-
The concept recognizes and efficiently organizes
third-party services.
don, England acquires North Sea data and can
techniques specifically toward optimized interre-
provide benchmarks on drilling rates.
lated drilling processes. These processes are
Technical integrity—A company has technical
refined in integrated services and alliances.1
integrity if it has procedures for planning, evalu-
Best-in-class—Comparing like services, products or equipment will produce a ranking from
License-to-operate—When acquiring permis-
Service execution—The tasks involved in coor-
Strategic alliance—See Alliance.
ating, recording, documenting, organizing and
worst to best. The term best-in-class is often
sion to drill, an oil company takes on certain
training that ensure service or product standards
used in integrated services contracts to specify
responsibilities to protect the environment and to
are achieved. When the standards are not
that the best is to be used for each task. The
operate in a safe manner. A company that shows
reached, procedures allow for corrective action.
premise is that if the best is used, then the qual-
its competency to undertake these responsibili-
ity of the whole project should be the best. How-
ties is said to have a license-to-operate.
Turnkey—A turnkey well is one that is drilled,
completed and commissioned to an oil com-
Multiskilling—A vital part of integrated ser-
pany’s specifications for a fixed price. With such
vices is the availability of personnel who perform
a contract, the risks for the service company are
more than one specific task. This enables person-
unlimited if difficulties arise. Quality standards for
nonessential activities of a company, respectively.
nel to be used efficiently on board a rig or plat-
the delivered product must be set and monitored.
Noncore activities are often considered those that
form.
ever, this may lead to a costly, over-engineered
solution that may not be necessary.
Core, noncore—These are the essential and
do not provide competitive advantage or that can
be performed more economically by outsourcing.
Data acquisition—Directional measurements,
petrophysical parameters, geological data and
reports, geophysical data, drilling reports, com-
Outsourcing—Contracting out work to competent external suppliers. What is considered a
noncore activity is usually the first to be
outsourced.
Partnering—This term acknowledges the close
Value chain—The step-by-step links of a process that add value to that process. A value chain
may also include logical grouping of functions.
Value driver—See Drivers.
Well construction—The process of drilling,
completing and evaluating new wells.
pletion drawings and reservoir parameters are
relationship between an oil and a service com-
examples of data acquired before and during the
pany working on one project. The partnership
involved in the design, planning, execution and
life of a well.
pursues common goals and, through commitment
evaluation during the life cycle of a well.
Delayering—The process of reducing the number of management layers to accelerate commu-
and trust, improves project efficiency.
Prequalification—Before a service company is
nication between the top and bottom of an organi-
allowed to bid on a contract, it may be asked to
zation.
establish its credentials and ability to undertake
Well engineering—The engineering process
Well management—The process of maintaining well production through workover, intervention and associated evaluation.
Workscope—An outline of all the tasks
a service or group of services. This prequalifica-
involved in a project. The workscope should be
of an organization, usually in terms of the num-
tion allows a company to bid for a contract or
present in all contracts, but is essential for incen-
ber of employees.
series of contracts. Prequalification documents
tive contracts.
Downsizing—The practice of reducing the size
Drivers—The key forces that provide the moti-
may include details such as the financial strength
vation to move forward in pursuit of goals. In
of the company or the operational or technical
incentive contracts, it is important to recognize
support provided, and are usually valid for a lim-
drivers and gear rewards to them. For example, if
ited period or limited scope of work.
time is the driver, then incentives should be
1. De Wardt JP: “Lean Drilling—Introducing the Application
of Automotive Lean Manufacturing Techniques to Well
Construction,” paper IADC/SPE 27476, presented at the
IADC/SPE Drilling Conference, Dallas, Texas, USA, February 15-18, 1994.
given for finishing early.
17
group was formed to address the growing
demand for integrated services by applying
project management, well engineering
expertise and optimum technology (right).
Coordination is from group headquarters
in Montrouge, France and regional centers
in Aberdeen, Scotland; Caracas, Venezuela;
Houston, Texas, USA; and Jakarta, Indonesia. Regional centers provide support and
expertise for all integrated services projects
and take advantage of the Schlumberger
Information Network, a worldwide communications system.10
Schlumberger services
Third-party services
Well construction
• Project management
• Well engineering
• Technology
Well management
Outside suppliers
nIntegrated project management. Integrated services is provided through Schlumberger’s Integrated Project Management Group. This group uses experienced project
managers, well engineers and the technical strengths of Schlumberger product lines,
third-party services and outside suppliers to provide two products: well construction
and well management.
Well Engineering
10. The Schlumberger Information Network (SINet) links
over 17,000 users at more than 400 worldwide locations via their computers. It allows transfer of digital
data including e-mail, documents, data bases,
graphics and log files. For more information, see:
Clark R, Danti B, Guthery S, Jurgensen T, Keddie J,
Kennedy K and Sims D: “Building a Global Highway
for Oilfield Data,” Oilfield Review 5, no. 4 (October
1993): 23-35.
11. Data acquisition is one example of services required
by all three components of well engineering.
The simplest level is service execution,
involving the coordination of primary service
company and third-party services. A rigsite
coordinator is responsible for on-site coordination. Well testing is an example of service
execution since it involves the coordination
of several services. The senior well test supervisor provides rigsite coordination and is the
focal link with the oil company (see “Integration in Well Testing Services,” page 13).
The next level is project management—
where service company responsibilities
increase, but the conceptual design often
remains within the oil company’s control. In
this case, there is more interaction with the
oil company and greater team involvement.
This level of service includes planning the
execution of services in addition to implementing management systems aimed at
continuous improvement. The service company is involved in many aspects of project
management and also has responsibility to
develop detailed work schedules from the
operational requirements specified by the
oil company.
Finally, the most complex level of service
integration is product delivery (see “BP
Machar,” page 20). In addition to project
management, designing the best technical
solution is part of the responsibility of the
service company. During execution, the
integrated services well engineer monitors
progress to ensure technical integrity and
compiles information on performance and
efficiency. This information is later used for
process mapping and improvement.
When oil companies are granted a license
to operate in a particular sector, specific
commitments and responsibilities to governments and their agencies form part of the
license agreement. When implementing an
integrated services contract, the oil company must ensure that the service companies involved are competent to take on certain of these responsibilities.
Schlumberger has adopted a three-part
strategy to meet these requirements:
• maintaining technical integrity through a
DESIGN-EXECUTE-EVALUATE (D-E-E)
process, as well as other internal quality
control and quality assurance programs
• organizing project management by teams
• optimizing the learning process using
data management.
Product Delivery
Operator-contractor interaction
Well engineering forms the framework for
integrated services projects and is built
around three components: well construction,
well management and data acquisition.
Well construction involves drilling, evaluating and completing new wells. It
includes engineering the conceptual
design, writing detailed plans and forming
the team of service companies required to
construct the well.
The detailed organization is tailored to a
particular project. However, similar services
are usually grouped together. Well construction forms three natural groups of services:
drilling operations, integrated drilling services and data acquisition.11
Well management is the lifetime maintenance of well production and includes production monitoring through data acquisition
and, when necessary, workover operations
with the associated drilling, stimulation and
completion services. The primary value
drivers are cost and productivity over the life
of the well.
Data acquisition is the provision of reservoir information as an independent integrated services contract. Data are acquired
for seismic mapping, pressure transient analysis, detailed log interpretation and core
analysis. Most data are recorded during well
construction and well management, but
may also come from seismic surveys or
campaigns involving several wells. The primary value drivers are the quality and quantity of data and the acquisition cost.
Integrated services projects may be simple
or complex (right). Although this can be
seen as a continuum, one can identify three
distinct levels of integrated services.
Design &
Management
Project Management
Programming
Service Execution
Planning
Coordinate On-site supervision
product line
and thirdCoordinate party services
product line
services
Well Engineering
Involvement
Complexity
nLevels of integrated services. The simplest level of integrated service is service
execution. At the most complex scale—product delivery—there is significant oil
company-service company interaction through well engineering and project
management.
Oilfield Review
Conceptual
design
nDESIGN-EXECUTEEVALUATE (D-E-E)
process. The D-E-E
process used by
well engineering
helps develop a
learning culture.
The design stage
may include conceptual design as
well as detailed
design and planning. The execute
stage follows bestpractice procedures
to implement the
design. Finally,
evaluation has two
objectives: a rigsite
quality check to
allow continuous
improvement and
an end-of-well
review to provide
feedback for future
designs.
DESIGN
EVALUATE
Detailed
design &
planning
Rigsite
continuous
improvement
EXECUTE
Dedicated
Project manager
Designated
Health, safety
& enviroment
Coring service
manager
Testing fluids
service
manager
Well engineer
Fluids service
manager
Directional
drilling/MWD
service manager
Mud logging
service
manager
Bits service
manager
Directional
drilling/MWD
services
Mud logging
services
Bits services
Base
Rigsite
Coring services
Rigsite
coordinator
Testing services
Fluid services
Maintaining Technical Integrity
For Schlumberger, the D-E-E process is central to ensuring that technical responsibilities are met. The three stages of the process
form a feedback loop (top).
Tasks performed in well engineering follow design procedures and standards, are
backed up by documentation, and are subject to an audit process that allows for
design review and, if necessary, change.
Plans are drawn up with achievable milestones within feasible time limits and
require commitment of resources by all parties involved. The design process leads to a
clear definition of the personnel and skills
required to perform all tasks.
Summer 1995
Execution of the design also follows welldefined procedures. Each stage of plan execution is scrutinized to ensure quality. If
design criteria cannot be met—for example,
unforeseen geological problems are
encountered during drilling—then procedures allow for design changes.
Evaluation comes through quality checks,
which ensure that design standards are met or
exceeded. At the end of a project, the results
and performance are reviewed by all team
members and compiled into a final report.
Future designs take into account this evaluation so that improvements in quality and
efficiency are continuous. The design, execution and evaluation process helps develop
a learning culture—discussed later in this
article—which is central to a consistent and
coherent approach to well engineering.
nProject organization. The project
organization for an
integrated drilling
service includes
three new Schlumberger employees:
the well engineer,
the project manager and the
rigsite coordinator.
During project execution a dedicated
team works on the
project (red). Other
members of the
team (blue) are
assigned to the
project, but may
work on several
other tasks.
Project Management and Teamwork
How a service company organizes its work
is only half the story. Of equal importance
in maintaining technical integrity is how a
service company itself is organized. Since
service companies are technical companies,
each staff member has a clearly defined role
and set of responsibilities in the organization. New roles have emerged as integrated
service contracts have grown in complexity.
Increasing numbers of services are involved
as projects become more demanding.
Schlumberger organizes projects using a
team of people with sharply defined roles
and responsibilities (above).
Functions have emerged that are new to
the service sector and are required for proper
(continued on page 23)
19
BP Machar
The UK has more than 200 undeveloped offshore
wanted to know how the reservoir would perform
stabilization facilities. The plant consists of two-
oil and gas fields, each containing an estimated
under long-term, steady-state production before
stage, gas-oil separation with pumping and
average of less than 50 million barrels (bbl) of oil
committing to a development plan.
metering to the quick-disconnect export line.
equivalent. Nearly all these fields are uneconom-
BP decided to use an EPF to produce from two
To comply with UK safety case regulations,
ical to develop using the traditional fixed plat-
previously drilled wells.2 Production would pro-
Sedco 707 had to be considered a fixed installa-
form. Early production facilities (EPF) have been
vide dynamic reservoir data and, at the same
tion production facility. Sedco Forex prepared the
introduced to this area as an intermediate devel-
time, early payback by selling oil within months
safety case with the objective of designing and
opment method. An EPF project allows earlier
of the project start.
operating the Sedco 707 EPF with minimum risk
returns on investment while obtaining better
The contract was awarded to an alliance—
to personnel.
information on the reservoir, leading to an opti-
known as TAP, comprised of Schlumberger,
mum final development program. One EPF pro-
Coflexip Stena Offshore and ABB Vetco Gray—to
Schlumberger-Riboud Product Centre, Clamart,
ject for BP Exploration illustrates the benefits of
provide integrated EPF systems. Schlumberger
France. To minimize installation time and verify
integrated services at the most complex
provided the mobile semisubmersible rig, Sedco
correct assembly, the EPF was built in modular
level—product delivery.
707, and drilling, completion, production and
sections that were connected and tested at the
The EPF was designed and constructed at the
testing services; ABB Vetco Gray provided the
construction site before disassembly and trans-
Machar is one of several fields forming the East-
subsea hardware; and Coflexip Stena Offshore
port to Aberdeen, Scotland and installation on
ern Trough Area Project—a group of four large
chartered the loading tanker and provided the
Sedco 707.
fields and three smaller fields operated by BP
flexible export line (next page).
In 1972, BP discovered the Machar field.
and Shell Expro
(right).1
Estimated reserves for
the group are 380 million bbl of oil and 1.2 tril-
An oil tanker is used for storage and shuttle
Sedco 707 was converted to an early produc-
transport to the Tetney terminal on the Humber
tion facility by installing crude oil processing and
estuary, England. The tanker is a double-sided,
lion cubic feet (Tcf) of gas. Machar is the secondlargest field and has estimated reserves of about
60 million bbl of oil and 160 billion cubic ft (Bcf)
of gas.
Although the field was discovered 23 years
ago, development economics had been uncertain. The reservoir is a dual-porosity fractured
chalk with most of the oil held in a tight rock
Forties
matrix. Production is from the fractures. But BP
Monan Mungo
Mirran
Marnock
Skua
Heron
Scoter
Machar
Aberdeen
N O RT H
20
S E A
■ Machar field location.
Machar is in a group of
fields forming the Eastern Trough Area Project
in the North Sea.
Recent changes in UK
legislation and the quality of integrated projects have allowed
development of these
marginal fields.
■ The floating production facility (FPF). The Machar FPF consisted of the semisubmersible, Sedco 707, fitted with an early production facility (EPF), hooked up via a
1-mile [1.6-km] export line to a dynamically positioned tanker—Stena Savonita—and connected to two wells by the ABB Vetco Gray production riser.
double-bottomed terminal tanker built in 1992.
each end, the line forms a catenary, allowing
advice on key issues such as well control, statu-
Over a two-month period the 108,000-ton tanker
both rig and tanker some movement before hav-
tory approval, reporting, health, safety and envi-
was modified at a dry dock in Hamburg, Ger-
ing to disconnect—something that should not
ronmental and contractual issues.
many. A variable-pitch propeller was fitted along
happen within a 25-year storm cycle.
The project was executed in phases: engineer5/8-in.
with two bow thrusters and one stern thruster to
ABB Vetco Gray designed and built the 6
provide dynamic positioning. In addition, bow-
[16.5-cm] heavy-wall carbon steel production
loading equipment and an oil-transfer telemetry
riser, providing the link between the two commin-
system were installed.
gled production trees on the seabed and EPF.
Oil is exported to the tanker via a 1-mile [1.6
The project was organized as an integrated
km] long, 6-in. [15-cm] diameter flexible subsea
team headed by a project manager. The project
flow line that has quick-disconnect couplings at
manager provided a single point of contact with a
both ends, allowing either rig or tanker to break
project executive committee made up of execu-
free from the line if necessary. The line is held in
tive management of the alliance partners and BP
place on the seabed with concrete mattresses. At
asset management. Reporting to the project man-
ing, well completions and mobilization, and,
finally, production.
The engineering phase covered detailed
design, purchase of long-lead items, well com1. “PRT Reforms Bolster BP Development Plan,” Oil & Gas
Journal 91 (May 17, 1993): 18-19.
2. Oldfield GA: “Early Production System for the UK North
Sea,” presented at the 9th International Floating Production Systems Conference, Genoa, Italy, May 25-27, 1994.
ager were interface engineers from the alliance
partner companies who liaised directly with BP
engineers on a daily basis. BP formed an integral
part of the organizational structure by providing
21
4000
The results of this integrated approach to the
Post-acid stimulation
inflow performance ratio
design of the well fluids and completion were
successful beyond expectation. The cleanup
Borehole flowing pressure, psi
3500
operation and stimulation program combined to
Bubblepoint
deliver a well capable of producing 30,000 B/D
with minimal drawdown. Prestimulation response
3000
showed a production rate of little more than 2000
B/D before pressure dropped below the bubble2500
point (left).
The Machar project entered the production
phase only 19 weeks after project approval. Pro-
2000
duction is expected to be 7 million bbl of oil in
one year.
Pre-acid stimulation inflow performance ratio
Following this success, the second phase has
1500
0
5,000
10,000
15,000
20,000
25,000
30,000
Flow rate, STB/D
■ Inflow performance ratio (IPR) before and after stimulation. The IPR, calculated from pressure analysis
before stimulation and cleanup, showed that the well could not flow above about 2000 B/D without the borehole flowing pressure (BHFP) dropping below the bubblepoint. After stimulation, a new IPR was calculated.
This showed that the flow rate could be more than 30,000 B/D with BHFP remaining above the bubblepoint.
been awarded to the same alliance. It calls for up
to 30,000 B/D of oil production while injecting up
to 40,000 B/D of water. The workscope includes
drilling and completing a new well and converting an existing well to a water injector. The EPF
will be upgraded to handle three-phase fluid flow
with an increased capacity limit of 35,000 B/D. A
pletion design and program preparation and
The alliance team recognized that a major
water treatment skid and a seawater treatment
statutory approval applications. Approvals were
stimulation program would be required to access
facility will also be added. Production is expected
also obtained for construction, procurement and
the full natural permeability of the fractures after
to last up to 18 months.
vendor supervision. At the same time, Sedco 707
overbalanced drilling. The proposed treatment
underwent quayside outfitting in preparation for
called for a cemented completion, selective per-
of the project, represents full product delivery
the installation of the EPF facilities. The field
forations and acid stimulation. Diversion of the
from planning and well design to drilling and
safety case was also submitted along with pipeline
stimulation fluids was considered key to the suc-
completion.
works authorization to the regulatory authorities.
cess of the completion. The detailed fluid design
The well completions phase saw mobilization
of Sedco 707 to the field to tie-back and run the
completion string on the two wells. One well had
called for:
• detection of natural fractures along the wellbore trajectory
been drilled in 1987, and the other was drilled in
• optimal drilling fluid selection
1992 and then redrilled as a high-angle well and
• cementing design
successfully tested in December 1993 as part of
• wellbore preparation and perforating design
the field development.
• stimulation program.
Dowell used the latest techniques to stimulate
and fracture the new high-angle
well.3
An inte-
Drilling fluid design had to take into account
that mud would enter the fracture system and that
grated approach was taken that used the com-
cleanup would be easier if the fractures were
bined services of Dowell fluids engineering.
quickly sealed. Cementing design needed to provide hydraulic seals without severe cement
losses in the fractures.
The stimulation program was planned to
reestablish communication with the natural fractures and clean out mud and solids to restore permeability. The design also had to connect fractures not intersected by the well and, if
necessary, induce and etch fractures in the tight
rock matrix.
22
The new well, drilled by Schlumberger as part
3. Gilchrist JM, Stephen AD and Lietard OMN: “Use of
High-Angle, Acid-Fracture Wells on the Machar Field
Development,” paper SPE 28917, presented at the European Petroleum Conference, London, England, October
25-27, 1994.
ID
26
27
28
29
30
31
32
Name
Well/ rig Location
Arrange site survey
Mobilize vessel
Conduct survey
Analyze survey results
Feedback to drilling contractor and authorities
Program shallow gas and mooring plans
Jan
Feb
March
April
May
Normal
Summary
Operation
Milestone
4 Move rig off location
Move BOP and LMRP, connect
Full function test
Connect first riser
Run riser, test each 2 joints to 10K psi
Pick up slip joint and land joint
Move rig back on location
Connect kill, choke, rucker lines
Land BOP, latch, pick up test
Shear rams +VX+ casing test 1000 psi
Laid down landing joint
Pick up and latch diverter
Laid down all BOP equipment
Run test tool
BOP test 10K psi
Choke manifold test 10K psi
Pull test tool
Test surface equipment
Run wear bushing or seat protector
4 Pull out, laid down running tool
management of large integrated projects.
These include the well engineer, the project
manager and the rigsite coordinator.
The well engineer, the architect of the project, is responsible for designing an integrated services project: initially preparing
designs and options for bid proposals; selecting the best technical solutions provided by
service companies; and later producing the
detailed design and plans (above).
Equally important, during the execution
phase, the well engineer monitors progress
Preparation for next operation Hours Time from milestone
days/hours
Total time
Prepare for oil-base mud
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
6
6
R.O.V. on sea bed
R.O.V. to monitor
Prepare 17 1/2 BHA
Prepare shakers
Mix spacer water/oil-base mix
Mix kill mud
1:00
4:00
4:00
1:30
8:00
2:00
1:00
3:00
1:00
1:30
1:00
2:30
1:30
1:30
6:00
2:00
1:30
5:00
2:00
1:30
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
2
2
2
1:00
5:00
9:00
10:30
18:30
20:30
21:30
0:30
1:30
3:00
4:00
6:30
8:00
9:30
15:30
17:30
19:00
0:00
2:00
3:30
and performance, resolving any unexpected
problems or modifying plans if there is a
change in scope of the project. Duties
include ongoing performance reviews and
preparation of the end-of-well report.
Detailed evaluation allows continuous
improvement during a project, and the endof-well report shows how improvements
can be made in the next project.
For example, if drilling difficulties occur
across a particular shale, the problem may
be resolved immediately by lowering the
mud weight, drilling at a lower rpm or
modifying the bottomhole assembly. How-
■ Time breakdown
of a well construction. Well engineering details every
task required to
construct a well
and allocates time
to the nearest half
hour. From this, a
less detailed bar
chart is produced
showing the major
operations and
milestones. Costs for
the whole project
may be estimated
from this detailed
analysis in preparation for a bid.
0:30
4:30
8:30
10:00
18:00
20:00
21:00
0:00
1:00
2:30
3:30
6:00
7:30
9:00
15:00
17:00
18:30
23:30
1:30
3:00
ever, before the next well is drilled, the problem must be analyzed and an optimum solution chosen.
The project manager provides the client
interface responsible for efficient management of the work program. Tasks of the project manager include building the integrated
services team at the beginning of the project, reviewing the design and drilling program with the client and well engineer, and
various other tasks that depend on the scope
of the project.
23
Conceptual
design
Detailed design
and planning
Execution
Evaluation
Rigsite coordinator
Foreman
Project manager
Builder
Well engineer
Architect
Fluid
services
engineer
Drilling
services
engineer
Well
engineer
Rig
engineer
Logging
engineer
Well testing
engineer
nThe well engineering contribution to well construction. The well engineer is the architect of the project and is heavily involved in the conceptual and detailed design stage.
The project manager is the builder assigned to the project during detailed design and
has overall responsibility during the execution phase. The rigsite coordinator is the foreman who oversees the work at the wellsite. All three contribute to the review and evaluation of the project with the project manager as chair.
Time-related incentive element, $
Model for Function of Incentive
Drilling
Well test
Completion
Stimulation
Quality-related incentive element, $
Incentive Principle
Cumulative contractor revenue
Day rate
Penalty
Incentive
Lose
Win
Time
Target
24
Cap
nTypes of incentives. Incentive contracts may be
based on time,
quality or a combination of both (top).
A drilling contract
would be driven by
time, whereas a
stimulation contract
would be driven by
the improvement of
the well after stimulation—quality
driven. The incentive principle (bottom) is for the contractor to “win” if a
target is beaten. As
soon as the target is
missed, the contractor pays a penalty.
Many contracts
have a fixed
penalty, so that the
contractor is not
open to unlimited
risks. When the
penalty cap is
reached, payment
may revert to a traditional form such
as day rate.
Project success depends on smooth functioning of the integrated services team and
each team member must have ready access
to available data in order to make sound
technical decisions. Physically locating all
members of the team in one place optimizes
communication and information flow. To
this end, service companies—including
third parties—and oil companies need to be
open and willing to share responsibility, so
that the best skills converge.
During the planning phase, the project
manager defines the critical path, based on
long-lead items, and plans logistics with all
parties involved.12 This ensures that all components, tools, consumables and services
are available on location on time. Proper
base, office and communication facilities
organization is crucial to success.
The project manager oversees project tasks
and schedules, time and cost control, safety,
environment and emergency preparedness,
quality assurance and reporting. Other
responsibilities include reviewing ongoing
performance, holding an end-of-well review
with all participants, and generating final
reports. In all respects, the project manager
is the “client” to the service companies.
Another key position is the rigsite coordinator who supervises and coordinates the
service companies involved in the project at
the wellsite. One major role is to ensure
compliance with the work program and
optimal efficiency of job execution. Other
tasks include updating daily forecasts and
activities, and anticipating resource requirements to meet project demands.
These three project management functions represent a new area of business for
Schlumberger ( top ). Positions are being
staffed by personnel with the breadth and
depth of skills required. These include
expertise in well engineering and project
management, and wide international experience in well construction, well management
and well engineering. To ensure sufficient
availability of personnel, Schlumberger is
implementing an internal training program
for current staff members and recruits.
For integrated services to succeed, project
objectives must be clearly specified. For
example, a well being drilled may become
a producer, an injector or a waste-disposal
well. The overall standards and criteria for
each are different and must be conveyed
throughout the integrated services project
organization so that the workscope can be
accurately defined. Once objectives are
agreed upon, performance and cost criteria
are established against benchmarks. If this
structured approach is followed, an incen-
Oilfield Review
No Learning
Fast Learning
Slow Learning
New Technology Applied
Days
tive package may be geared to project
objectives.
Performance incentives may come in different forms and combinations within a single project. For example, if the main value
driver is time, this is the key criterion. Alternatively, well production may be the main
objective. In this case, quality measurements will be used as the criteria. Safety and
environmental performance appear as
incentives in most contracts (previous page,
bottom).
One of the key aspects of project management is continuous improvement. For example, if a project involves drilling 15 wells,
then the fifteenth well should take substantially less time to drill than the first (right ).
A learning organization defines specific
goals that are linked to its financial performance—for example, to cut rig time reduces
well costs. The organization ensures that
actions are directed toward meeting these
goals, remembers how decisions were made,
accurately monitors performance, builds an
accessible reservoir of experience, and uses
this experience to adapt its practices to do
things better next time.13
To extend this learning approach beyond
the next well and to apply it to projects anywhere in the world, a system must be created that generates and propagates best
practices rapidly. So, although the next project may be geologically different or organized in a different manner, the best practices may be applied immediately. The
learning curve becomes steeper as the
knowledge base grows deeper.
The Future
Reducing cost and improving business efficiency without compromising the quality of
work will be achieved through project management and teamwork linking innovative
technology, information technology and
new ways of doing business (right). Integrated services is one of the new business
methods showing clear, tangible benefits to
both oil companies and service companies.
Four key factors determine the success of
integrated services projects. The first is
teamwork. Oil and service companies must
work together in open, trusting relationships, sharing data, expertise and ownership
12. Long-lead items are ones that take a long time to
manufacture or deliver.
13. Thorogood JL: “Organization, Integrity,
Learning—The Keys to Success in Well Construction,” paper IADC/SPE 29337, presented at the
IADC/SPE Drilling Conference, Amsterdam, The
Netherlands, February 28-March 2, 1995.
Summer 1995
Days
Optimizing the Learning Process
Well sequence
Well sequence
nLearning curves. Examples of learning shown by reduced drilling time over a
sequence of wells: no learning (top left), fast learning (top right) slow learning (bottom
left), and application of new technology (bottom right).
Oilfield technical innovation
Information technology
Way forward
Improved
efficiency
and profitability
Industry restructuring
nThe way forward. Three strategies will reduce E & P costs: new
oilfield technology, information technology and new business relationships. Schlumberger’s ClientLink initiative provides the software data base to manage these three approaches.
of problems and solutions. The second is
objectives. Common objectives, targeted at
the end product, enable all parties involved
in the project to strive for the same goals,
improving efficiency and performance. The
third is technology. Integrated services provide a business environment that allows oil
companies and service companies to use
the optimum technology for product delivery and to take maximum advantage of
information technology. This not only leads
to efficient use of the latest techniques to
complete and manage wells, but also provides rapid, effective communication. The
fourth is shared benefits. Perhaps the most
important factor in cementing firm business
relationships is sharing the rewards from
reducing operational costs through structured incentive packages.
—AM
25
Alliances in the Oil Field
C. Brent Austin
Steve Dole
PanCanadian Petroleum
Calgary, Alberta, Canada
Today’s business climate is encouraging oilfield operators and contrac-
Walt Chmilowski
Gregg Vernon
Calgary, Alberta, Canada
the competition.
Ty Watson
Denver, Colorado, USA
700
16
Wells
650
15
BOPD
600
14
550
Average BOPD/well
Richard Lewis
John Thompson
Mike Vinson
Houston, Texas, USA
cutting costs and making the most of their resources—and gaining on
Producing wells, in thousands
J. Harmon Heidt
Amoco Exploration and Production
Denver, Colorado, USA
tors to join forces. Alliances are one of the ways oilfield companies are
■ Reduction in well
productivity. Since
the 1980s, the
number of oil wells
has increased, but
the number of barrels of oil per day
(BOPD) produced
per well has fallen.
(Adapted from Adams
et al, reference 1.)
13
500
12
81
82
83
84
85
86
87
88
89
90
91
92
Year
For help in preparation of this article, thanks to Rick
Adams, Mobil Oil, Midland, Texas, USA; Hervé Anxionnaz and Jean-Pierre Delhomme, Schlumberger Wireline
& Testing, Clamart, France; Andy Cart, Amoco Production Company, Houston, Texas; Dave Church, Dustin
Free, Jay Haskell, Ed Nordmeyer, Jerry Richards, John
Thompson and DJ White, Dowell, Houston, Texas; Roy
Dove, GeoQuest, Houston, Texas; George Dozier, Dowell, Bakersfield, California, USA; Tony Fondyga and Pat
McKenna, Wireline & Testing, Calgary, Alberta, Canada;
Roger Goodan, Schlumberger Integrated Project Management, Houston, Texas; Gary Griffith, Scott Mathis and
Stephen St. Amand, Marathon Oil Company, Lafayette,
Louisiana, USA; Joel Guttormsen, Conoco Canada Ltd.,
Calgary, Alberta; Gary Horton, Anadrill, Lafayette,
Louisiana; Jeff Icenhower, Amoco Production Company,
Denver, Colorado, USA; Bobbie Joines, Dowell, Denver,
Colorado; Joe Mach and Scott Scheid, Wireline & Testing, Houston, Texas; Mike Mathews and Bob Murray,
Dowell, Lafayette, Louisiana; and Brian Taylor, Dowell,
Midland, Texas.
In this article, BRACKETFRAC, Charisma, DESC (Design
and Evaluation Services for Clients), DipFAN, FasTex,
FracNPV, GeoFrame, HyPerSTIM (High-Permeability
Stimulation), PCM (Precision Continuous Mixer), SediView and SPIN (Sticking Pipe Indicator) are marks of
Schlumberger. SUMIC is a mark of Statoil.
26
In the oil field, two factors drive profits. The
first, market price of oil or gas, is governed
by many elements, such as political stability,
economic growth and the weather, all of
which are outside the control of operators.
However, the second factor, production
cost, can be controlled to some degree by
the industry.
During the past decade, market price has
stabilized—albeit at a moderate level—but
production costs continue to increase. Wells
cost more to drill and bring on stream
because much of the easy oil is gone, leaving behind oil that defies production by
conventional techniques and oil in deeper,
more complex reservoirs in frontier areas.
Total production costs remain high because
productivity per well has declined and the
techniques and materials required are generally more expensive (above ).1
Striving to remain profitable, oil companies are taking action in two areas to control
costs. First, they are redefining their business, identifying core competencies and
outsourcing noncore activities. Second, they
are changing the way they do business,
gradually converting the arm’s-length relationship with contractors into more cooperative collaborations to eliminate redundancy and boost efficiency, exploiting new
technologies to enhance productivity.2
Oilfield business relationships take many
forms. Volume discounts, turnkeys, service
bundling, integrated services, joint ventures,
partnerships, alliances—each has a place in
the continuum of business practices, each
with different levels of cooperation and
Oilfield Review
trust. Volume discounts and turnkeys are
variations on the traditional way of doing
business. Jobs are bid, whether by well or
by project, and job specifications are set by
the operator. The service company reacts,
then executes the job on demand.
In a second category, service bundling
and integrated services are new ways of
doing business that are gaining acceptance,
especially outside North America. Service
bundling gathers several services under one
contract and concentrates the points of contact between the operator and contractors.
Here, the operator still provides all the
specs, and the service supplier executes the
job. Integrated services contracts span a
wide range of activities, from service execution—performing bundled services—at the
most basic end, to product delivery at the
most sophisticated end (see “Integrated Services,” page 11 ). Product delivery, in which
the product may be an offshore platform, a
well or some other complicated project,
Entry
Supply
assurance
Quality
management
entails conceptual design, process planning,
service execution and evaluation.
Joint ventures tend to denote shared
equity and sometimes result in acquisition
of one party by the other.
The third category, and perhaps the
newest in the oil industry—certainly the
hardest to define—includes partnerships
and alliances. Partnerships are defined by
the Journal of Petroleum Technology as
“short-term, project-specific relationships
between supplier and client that seek to
gain greater economic value for both parties.”3 Alliances are similar to partnerships,
except they are designed to persist beyond
the scope of individual projects. Other definitions exist, but an alliance is defined here
as a long-term relationship between two
companies that furthers their common interests over a specific range of activities.
Although both are new business practices
in the oil industry, alliances differ from integrated services contracts. Under an inte-
Focused
Enhanced
Established quality
expectations
exceeded
All focused attributes
plus mutual business
and profitability growth
due to enhanced
cooperation
Competitive
total system cost
Development
cooperation
Effective quality
system
Supply chain
management
Business
results
optimization
Controlled
access to both
parties’ process
and information
systems
Synergistic R & D
1- to 3-year
duration
Project-specific
R&D
Easy agreements on
rights of development
alliances. As an alliance evolves,
the partner companies share more
strategies, risks and rewards.
Long-term view
of outcome
Significant
improvement in
both partners’
perfomance
Active steering
committee
Regular meeting
review
Risk sharing in
pursuit of objectives
Long term, 3+
year duration
Commitment of
significant resources
by both parties
Feedback at
all levels
Integration of
management
planning
Partnership
measurement
system to address
total quality and value
of partnership
1. Adams R, Englehardt S and Free D: “Forming a Customer-Supplier Alliance in an Exploration and Producing Environment,” presented at IMPRO94, The Juran
Institute’s Conference on Managing for Total Quality,
Buena Vista, Florida, USA, November 6-8, 1994.
Summer 1995
All enhanced and
focused attributes
plus:
An agreement to
achieve strategic
objectives through
interdependence
A continuity strategy
nFour stages in the evolution of
Strategic
Sharing of rewards
Optimum trust
Highly synergistic
R&D
2. de Wardt JP: “Strategic Alliances: Where are We
Headed?” World Oil 216 (February 1995): 103-107.
3. “Pressed into Service,” Journal of Petroleum
Technology 46 (March 1994): 198-200, 223.
King GE: “Improving Quality Control in Alliances and
Partnering,” Journal of Petroleum Technology 46
(March 1994): 192.
grated services contract, the client assigns
responsibility to the supplier to reduce the
client’s costs. In an alliance, the supplier
accepts responsibility to reduce client cost,
and the client takes on responsibility to
ensure the supplier’s profit, often by assuring
future business to the supplier. The two sides
work together to reduce costs and improve
profitability for all involved. Trust and confidence in supplier commitment make bidding each service or per well a thing of the
past.
However, integrated services and
alliances are not mutually exclusive. An
integrated services project may be offered to
an alliance partner, or may evolve into an
alliance. In fact, most alliances start out as
tests for a certain period of time, then if successful, may become self-renewing, sometimes called evergreen. Not written as long
contracts, the terms of an alliance often fit
on a single page.
Alliances themselves take many shapes.
An alliance may be an agreement between
an operator and a service company for a
single service, or it may embrace several
companies or several product lines within a
company to create what is called an integrated alliance.
Some alliances cover one geographic area
or business unit; others encompass worldwide activities. The alliance between Texaco and Dowell, for example, covers all
pumping services for Texaco’s North American operations (see “DESC in an Alliance:
Texaco,” page 43 ). The alliance between
Oryx Energy Company and Schlumberger
spans wireline, testing and logging-whiledrilling services worldwide.
Service companies can form a brand of
alliance among themselves—more a consortium, or partnership, following the definitions in this article—to offer complementary
services when the market is for integrated
services. Oil companies forge similar partnerships to develop their assets.4
“Strategic alliance” often describes
alliances that are part of the partner companies’ strategies, and implies that the companies share their strategies openly. Few oilfield alliances so far have reached such a
level of cooperation and openness, but that
is the goal to which many aspire (left ).
4. Nicandros CS: “North Sea Trends Typify Industry’s
Worldwide Adjustment to Change,” Oil & Gas
Journal 91 (November 8, 1993): 47-53.
Hamel G and Doz YL: “Collaborate with Your
Competitors—and Win,” Harvard Business Review
(January-February 1989): 133.
27
While this manner of association is relatively new to the oil business, it has been
practiced by other industries, notably in
manufacturing, for up to 15 years. Kodak,
Apple Computer, Siemens, Ford Motor
Company, Motorola, Toshiba and
International Business Machines are just a
few of the companies with experience in
gaining efficiency through alliances.
Alliance analysts have a rich selection of
ongoing and past alliances from which to
draw analogies, along with success and failure factors (see “The Alliance as a Relationship,” page 34 ).
Efficiency Improvements
Through Alliances
The cooperative spirit of an alliance changes
the way problems are approached. In the
quest to cut costs, it means not dwelling on
contractor profit, but cutting total project
cost (next page, top). To uncover where cuts
can be made, every process in the entire
project must be analyzed and examined for
inefficiencies. Alliance partners construct a
description, called a process map, for each
process. A process map may be a list of
steps or a flow chart (next page, bottom
left and right ). The total project is analyzed
and individual processes are retained only
if they add value. Improvements are made
to the remaining processes, or entirely new
processes are developed, and the new processes are remapped, giving continuous
improvement. 5 Decisions on how to
improve a process come from the alliance
partners, and team members have the
power make the necessary changes.
Where to start cutting costs? An economics professor would say, cut first where
there are the easiest and biggest gains.6 In
today’s development-oriented oil field,
pumping services can often account for the
majority of the cost of a well (below ). These
have become the early targets of companies
trying to increase efficiency.
Process mapping can show where redundant efforts are undermining efficiency. For
example, before one alliance, stimulation
engineers from both sides would spend time
designing a frac job. Soon after the start of
the alliance, the engineers from both companies completed the exercise of mapping their
fracture design processes. The results
showed the two processes to be duplicates.
200
Thousands of dollars
150
100
50
Through the alliance, now a frac job is
designed jointly, and then modeled by the
service company engineer, freeing the oil
company engineer to spend time on other
projects that add more value—in some cases
selection of other wells to be stimulated,
called candidate recognition. In other cases,
the optimal division of labor may assign candidate recognition and job design to the service company engineer, leaving the oil company engineer free to develop future growth
opportunities. In a growing number of
alliances, the oil company no longer
requires a representative on site for the job.
The streamlined process is more efficient,
but trust in the alliance partner is crucial to
the success of such a scheme (page 30 ).
Eliminating bidding is another example of
increasing efficiency by slashing processes
that add no value. Through process mapping, some oil companies have found that
almost as much money is spent on the bidding process as on the job itself. An advantage of the alliance between Conoco
Canada Ltd. and Schlumberger Wireline &
Testing has been the time and money saved
by not bidding. Conoco Canada Ltd. previously required at least three bids for every
well. Specifying the logging program took a
half day; getting the bids back took another
5. For a review of oilfield applications of quality control,
assurance and management:
Burnett N, Harrigan J, Jeffries J, Lebsack T, Mach J,
Mullen D, Pajot D, Rat F, Robson M, Theys P and
Wohlwend H: “Quality,” Oilfield Review 5, no. 4
(October 1993): 46-59.
6. This idea was quantified somewhat by Vilfredo Pareto,
an Italian economist, and founder of the “80-20 rule:”
80% of the wealth is held by 20% of the people. Quality expert Joseph Juran extended this concept to the
analysis of problems in general: 80% of the problems
come from 20% of the possible causes.
0
np
ctio
ele
t
g
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ea
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Ve
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lea
ng
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ess
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ep
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nt
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Pla
na
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ing
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s
ott
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ite
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ing
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ng
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ll p
rre
we
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Fra
nRelative magnitude of cost sources in the life of a development well in a California field. Pumped materials are the greatest cost,
and so present the greatest potential for cost savings.
28
Oilfield Review
Product-based
system
Service-based
system
Percent
Percent
Alliances
15
15
5
5
30
30
Customer design, specification,
procurement supervision,
QA/QC and payables
Supplier profit
(traditional approach
focuses here)
Supplier equipment
(including depreciation
and recapitalization)
Supplier labor
(including overheads)
20
New total system cost
Price = 100%
Invoiced cost = 115%
Total system cost
Cycle time, productivity,
logistics, research, engineering,
market swings, utilization
and missed opportunities
nNew focus on costeffectiveness for
product-based and
service-based systems. The traditional
approach reduces
costs by cutting supplier profit. Alliances
achieve increased
efficiency by cutting
total system costs.
45
45
20
Supplier materials
Process A
(operator)
Process A
(service company)
Improved process A
(operator + service company)
Further improved process A
(operator + service company)
nAnalyzing a well stimulation process map. More than 6 ft [2 m]
long, this typical process map comprises more than 100 steps.
nTwo fracture-design process maps streamlined to create one,
more efficient process. Through continuous improvement, the
operator (pink) and service company (light blue) processes
become a new single process (purple). Further improvements
yield a process with optimum efficiency (dark blue).
Summer 1995
29
half day. The bids then had to be opened in
the presence of a witness. Comparing bids
was a job in itself, and since there was no
uniform format, this could take another day
or two. After selecting a contractor, Conoco
met with an accountant, then called the
contractor to announce the award. “In the
week I save by not bidding, I can identify
new prospects,” remarks Joel Guttormsen, a
geologist with Conoco in Calgary, Alberta,
Canada. “That’s adding value.”
An idealistic example of process streamlining through trust is the story of tubulars—drillpipe, casing and tubing. Mapping
the many processes from steel manufacturing and tubular construction through
deployment and finally recycling shows that
tubulars are picked up, put down, inventoried and inspected anywhere from three to
eight times each (next page ). Cutting out
redundant steps and checks yields the seamless circle of the ideally efficient process.
Most of the process lies outside the realm of
the operating company alone, but through
supply chain management—alliances with
other links in the supply chain—total process efficiency can be optimized.
Some alliances initially formed to address
drilling and pumping costs later expand to
enfold other services. Examples from three
North American oil companies show how
such alliances are increasing productivity
and cutting costs.
Preperforating
Amoco/Dowell engineers
select perfs.
Forward to local
Dowell coordinator.
Fracturing
Tree-up
Schlumberger coordinates
logging and perforation;
notifies Amoco of date.
Dowell engineer
designs frac.
Amoco coordinates
w/Schlumberger to
set wireline packer.
TD not OK
Amoco installs frac valve;
coordinates w/Dowell
to test casing.
TD OK
Copy to Schlumberger
Wireline & Testing;
prepare for job.
Dowell notifies Amoco
of total depth (TD)
and Amoco OKs TD
or cleanout.
An example of an integrated alliance
designed to increase drilling and completion efficiency is the multiservice, singleproject alliance between Marathon Oil
Company and the Schlumberger companies
of Anadrill, Dowell and Wireline & Testing.
Diamond Offshore Drilling was the drilling
contractor, and mud was provided by M-I
Drilling Fluids Company.
The challenge was to drill and complete
nine directional offshore wells in the Vermilion Block 331 field of the Gulf of Mexico. Marathon fielded an interdisciplinary
team that interfaced with the contractor
team, and all decisions were approved by
the new collaboration.
Perforating
Run gauge ring w/gamma
ray/casing collar locator.
Copy to Amoco
Offshore Integrated Alliance
Forward to local
Dowell coordinator.
Copy to Amoco
Dowell and Palestine meet
on location for equipment
layout and select frac
date; Dowell notifies
Amoco of frac date.
Log and perforate
Dowell coordinates for
pit/frac tank/lines
and coiled tubing unit.
Palestine coordinates
installing frac stack,
pit/lines separator
and watchmen.
Frac well;
shut in for 36 to 48 hours.
Dowell coordinates
with water supplier.
Palestine coordinates
hauling flowback fluid.
Amoco coordinates
w/packer company.
Run gauge ring and
junk basket;
set packer.
Amoco coordinates
for rig.
Rig pusher coordinates
for tools, water/packer
fluid, tubing and tree.
Run tubing and
land tree.
Rig pusher coordinates
rig-down and pickup tools.
Run wash tool;
wash to plugged-back
TD and test casing.
Well ready to perforate
Well ready to fracture
Well cleaned up and ready
to run production tubing
Turn over to production;
ready for sales.
nStreamlined process map from Amoco Southeast Business Unit alliance with Dowell.
30
Oilfield Review
Typical Tubular Supply Chain
Mill
Scrap
Make steel
Handle & load
Inspect
Manufacture
pipe
Inspect
Nondestructive
test
Inventory
Handle & load
Ship to pipe
processor
Process
Nondestructive
grades, threads
test
Inventory
Handle & load
Ship to
distributor
Pipe
Processor
Inventory
Distributor
Handle & load
Inspect
Inventory
Handle & load
Ship to inspection
company
Inspection
Company
Handle & load
Inspect
Nondestructive
test
Inventory
Handle & load
Ship to
operator
Operator
nProcess maps
describing the use
cycle of tubulars.
Traditional processes
allow tubulars to be
handled, inventoried
and inspected a
number of times
(top). Alliances
between links in the
chain permit elimination of redundant
steps, yielding the
ideally efficient process (bottom).
(Adapted from Amoco
ASAP 2000 program,
with permission.)
Handle & load
Inventory
Handle & load
Ship to
well
Utilize
Scrap
Allied Tubular Supply Chain
Scrap
Utilize
Make steel
Ship to
well
Manufacture
pipe
Handle & load
Handle & load
Process
grades, threads
Summer 1995
Ship to pipe
processor
31
alliance, Marathon normally wouldn’t
acquire these measurements while drilling
because of the high cost, but Anadrill drilling
engineers pushed for them, certain the measurements would make drilling safer, would
create a more stable hole and ultimately
save money. Compared with other recent
similar drilling projects conducted via “business as usual,“ or outside the alliance, the
Vermilion 331 team increased the average
drilling rate by 56% and decreased drilling
costs by 14% (below ).
Benchmarks were set in three areas: better-than-market financial compensation was
offered if drilling time, health, safety and
environment compliance, and well performance exceeded expectations. The joint
team worked to anticipate time-consuming
steps and solve problems rapidly. Drilling
time was minimized with topdrive to speed
tripping and connections, and with the help
of the SPIN Sticking Pipe Indicator program,
which requires downhole weight-on-bit and
downhole torque as inputs. Before the
Drilling
Ft/day
Cost/ft
1000
100
900
90
921
800
80
700
70
500
Dollars
600
Ft
nResults of Vermilion 331 integrated
alliance between
Marathon Oil Company, M-I Drilling
Fluids, Schlumberger Wireline &
Testing, Anadrill,
Dowell and Diamond Offshore
Drilling.
592
400
92
79
60
50
40
300
30
200
20
100
10
0
0
PanCanadian Stimulation Alliance
Completion
Days/gravel pack
Cost/gravel pack
7
6
500
473
6.6
400
425
4.8
3
Dollars
Days
5
4
300
200
2
100
1
0
0
Production
Business as usual
8000
7840
Bbl of oil equivalent/day
7000
Vermilion 331
Unlike the integrated alliance that drilled
Marathon’s Vermilion wells, most oilfield
alliances begin with a single service. An
example is the alliance between PanCanadian Petroleum and Dowell, the goals of
which are to assure high-quality stimulation
and to control treatment costs. In 1992, top
management at PanCanadian urged business managers to search worldwide for
more efficient production methods. Out of
that came the motivation to forge alliances
to optimize production and speed payout
( next page, bottom ). The alliance with
Dowell emphasizes finding the best technology for the problems encountered in
PanCanadian’s variety of assets, which span
a multitude of environments in Canada,
including shallow gas wells, deep foothill
exploration wells and wells producing
heavy oil.
A Dowell engineer—called a DESC engineer, for Design and Evaluation Services for
Clients (see “The DESC Engineer Redefines
6000
6030
5000
4000
3000
2000
1000
0
32
The completion phase also benefited from
the team organization and the risk-reward
financial structure. By focusing attention on
both productivity enhancement and process
cost reduction for the 15 zones completed,
the team was able to reduce average rig
time by 1.8 days and shave nonrig completion costs by 10%.
These savings were achieved while implementing the relatively new HyPerSTIM fracturing and sand control technique. The
HyPerSTIM technology, combined with
Marathon’s emphasis on sound completion
practices and the team’s attention to detail,
resulted in flow capabilities that averaged at
least 30% more than in the prealliance
completions (next page, top left ).7
While the overall project met or exceeded
expectations, it took time and effort to step
out of the comfort of long-standing roles,
responsibilities and communication lines. A
financial structure that gave all parties a
vested interest in achieving project goals
and an environment that promoted open
communication and risk taking was key to
the success of the project.
7. Mullen ME, Norman PE and Granger JC: “Productivity
Comparison of Sand Control Techniques Used for
Completions in the Vermilion 331 Field,” paper SPE
27361, presented at the SPE International Symposium
on Formation Damage Control, Lafayette, Louisiana,
USA, February 7-10, 1994.
8. For information on crosslinkers, breakers and other
fluid additives:
Brown E, Elphick J, Gulbis J, Hawkins G, King M and
Pulsinelli R: “Taking the Brakes off Proppant-Pack
Conductivity,” Oilfield Review 3, no. 1 (January 1991):
18-26. Also, see an article on advanced fracturing fluids in the Autumn 1995 issue of Oilfield Review.
Oilfield Review
Oil Well Performance Analysis
kh-normalized productivity index
4
3
Prealliance
Alliance without
HyPerSTIM
Alliance with
HyPerSTIM
2
1
0
Sand 1
Sand 2
Sand 3
Sand 4
Positive
Optimized
Early payout
Late payout
Traditional
Negative
Cash flow
nImproved well performance in
wells stimulated with HyPerSTIM
fracture treatment.
cult to predict, and engineers tend to err on
the side of surplus. A more efficient process
was developed by switching to a more
expensive PCM Precision Continuous Mixer
system, giving higher quality fluid, and no
waste.
Alliance engineers also examined the type
of crosslinkers in the frac fluid. Previously,
they had used titanate crosslinkers with
covalent bonds. Then they tried borate, with
ionic bonds, which are more flexible, so not
affected by shearing during passage through
perforations. Finally, they switched to an
encapsulated breaker to improve the breaking of the link created by the crosslinkers to
start fluid flowing out of the fracture.8 The
combination of new technologies yielded
improved fracture conductivity (right ).
In the deeper oil and gas wells, the
alliance team tested a new energy-assisted,
or foam, fracture technique that gave higher
productivity. “We did switch to more expensive products, but they have decreased our
total cost and increased our productivity.
The results of the alliance surprised us,” says
Steve Dole, coordinator for completions
engineering at PanCanadian in Calgary,
Alberta, Canada. “We thought we’d bottomed out on the cost per job by 1993. But
we’ve learned we can keep cutting.”
After two years, the alliance completed
1500 high-tech frac jobs, 700 cement jobs
and 140 conventional fractures all with reasonable cost, excellent quality and no losttime accidents—a perfect safety record. Jobs
are now scheduled to avoid delays during
periods of peak activity and to make better
Delayed payout
Land
Drilling
Completion
use of Dowell’s resources. This improved
resource utilization has resulted in reduced
costs for Dowell, thus benefiting both companies. The alliance is expanding to include
coiled tubing services and cementing, and
to plan longer-term actions. Through the
alliance, PanCanadian is now influencing
Dowell’s research in areas of special need,
such as fracturing techniques for shallow gas
wells and hydrocarbon frac fluid breakers.
Alongside the stimulation alliance is a
parallel alliance to add value to open- and
Stimulation Improvements
Future
benchmark
12
Normalized absolute open flow potential
Work,” page 40)—was posted to the PanCanadian office to interact with field development teams and provide a link with
Dowell research capabilities. Continuous
improvement teams were formed to analyze the entire stimulation process. Prior to
the alliance, PanCanadian had considered
the shallow gas wells deserving of only
low-technology fracture treatments. Stimulation engineers were pumping batches of
premixed frac fluid. Premixed fluid is less
expensive, but the quantity required is diffi-
10
8
Encapsulated
breakers
6
Borate
Titanate
4
2
0
nContinuous improvement in flow rates
by changing stimulation fluid. Normalized absolute openhole flow rate has
increased steadily as stimulation engineers optimize crosslinker and breaker
technology.
cased-hole logging and drillstem testing, initiated in 1993. PanCanadian has increased
its drilling activity from 413 wells in 1992 to
a budgeted 1250 in 1995, without increasing staff. To handle the increase in logging
activity, two additional Schlumberger personnel have been dedicated to the PanCanadian office; an applications development
engineer helps design logging programs,
and an evaluation services technical representative coordinates all logging and testing.
In an atypical exchange of expertise, a
third Schlumberger engineer has been seconded to the PanCanadian petrophysics
Production
nPayout curves showing traditional and optimized drilling and production.
Summer 1995
33
onded to the PanCanadian petrophysics
group for a two-year stay. Tony Fondyga,
with 15 years of wireline and testing experience, works with the geology and reservoir
groups to make decisions on the fate of wells
—whether to case or abandon. Working
within the PanCanadian group, Tony sees the
business through the eyes of the operator
and deals directly with service suppliers,
including competing wireline companies.
During the first two years of the alliance,
logging time and costs per meter have
dropped relative to PanCanadian’s prealliance average. Process improvements have
streamlined log data delivery by eliminating
log films and delivering digital log data
directly to an outsourced data library. Teamwork with the Dowell DESC engineer to
analyze cased-hole logs for fracture design
has led to improvements in the quality of
shallow gas well treatments. Plans call for a
Schlumberger interpretation specialist to
move into the PanCanadian office to work
on special projects and help the drilling and
development groups get better value from
their data.
Process
Bidding
Single Sourced
Allied Supply Chain
Strategizing
Not done
Local market
position and price
Developing strategic
issue jointly
Planning
Reactionary
Budgeted spending
and revenue
Optimizing value
and reducing cost
Research
Potential for
testing
Joint testing
Jointly developing
Designing
Supplier
reacting
Supplier responding
Supplier responsible
Scheduling
On demand
Supplier and operator
communicating
Supplier is scheduler
Operations
quality
As ordered
Enhanced for
incentives
Most effective
and efficient
Evaluation
Both are
separate
Joint effort
specific to incentives
Focused at total
system impact
Continuous
improvement
process
Microinternal
Centered around
incentives
Feedback in
every process
Reengineering
Not done
Changing tasks of
local process owners
Upstream suppliers
involved
Profiting
Spending vs.
revenue
Planned spendingactual costs
Enhanced revenues
and total system cost
■ Supply chain evolution.
Multiple Amoco Alliances
What makes an alliance successful? From
those who’ve done it, one of the first
answers is top-down commitment. The
alliance must have champions at the highest level. An example is the case of Amoco
Production Company. Early in 1992,
Amoco launched the Vendor Asset Materials Management (VAMM) team as part of a
company-wide business process reengineering effort. The VAMM team, led by US
Operating Group Vice-President Jerry
Brown, made a presentation to the seven
North American business unit managers,
urging alliances as a tool for lowering
investment costs and reducing controllable
operational expenditures. The Amoco Supplier Alliance Program, ASAP 2000, was set
in motion throughout the company to bring
a systems approach to managing supplier
relationships (above ).
The business unit managers were encouraged to create supplier alliances with the
service companies of their choice. Five
alliances have been built with Schlumberger
companies, and three with Halliburton
Energy Services. Each alliance is different,
but share some common features. “We have
a healthy concern for the profitability of our
alliance partners,” says Harmon Heidt,
Alliance Coordinator with Amoco in Den-
ver, Colorado, USA. “Our focus is on eliminating costs deemed to be unnecessary—in
all our operations, Amoco’s and our suppliers.” The following examples from three
Amoco business units demonstrate some of
the progress to date in increasing efficiency.
Early in 1992, John Morris, the operations
manager of the Southeast Business Unit
(SBU)—covering land operations in
Louisiana, east Texas, south Texas, Arkansas,
Mississippi, Alabama and Michigan—met
with major service suppliers to discuss
alliances. He anticipated a significant
reduction in operating costs associated with
reducing the number of suppliers. At
The Alliance as a Relationship
In French, alliance means marriage. And many
During courtship each side checks out the other,
sometimes coming as a surprise to those who
alliances seem to resemble marriages more than
and compares with others, looking for the most
founded the alliance—and the partners must work
they do other business relationships. After studying
attractive, compatible partner. Compatibility is
out problems and develop techniques for getting
37 alliances in different industries, Professor Rosa-
based on common values, principles, experi-
along. Trust is crucial and individual sacrifices are
beth Moss Kanter of the Harvard Business School,
ences, resources and hopes for the future.
made for the good of the relationship.
Cambridge, Massachusetts, USA, has found that
After the engagement, plans are drawn and the
As partners enter the “old marrieds” phase, they
relationships between companies grow or fail much
wedding closes the deal. The agreement is given a
can reflect back and recognize changes, changes
like relationships between people.1 She describes
name and made public. Executives from both sides
not anticipated at the start of the relationship. Col-
the four phases of an alliance as courtship, engage-
are invited to “meet the family.”
laborating becomes more effortless and routine.
ment, marriage and old marrieds.
The marriage phase begins as the partners set
up housekeeping together and grow as a family.
During this phase, differences are discovered—
34
Kanter also outlines the eight essentials “I”s in
an alliance that make for a strong “we”:
Wireline & Pumping Cost Analysis
400
Avg. benchmark
Avg. alliance
Thousands of dollars
350
300
250
200
150
100
May July
Sept
Nov
Jan
Mar
May
1991
July
Sept
Nov
Jan
1992
1993
Fracturing Cost Analysis
300
■ Amoco Southeast
Business Unit well
completion and
fracturing costs
and performance
before and after
the alliance with
Schlumberger.
Avg. benchmark
Avg. alliance
Thousands of dollars
250
200
150
100
May July
Sept
Nov
Jan
Mar
May
1991
July
Sept
Nov
Jan
1992
1993
Well Performance
Absolute open flow/net feet of
perforation, Mcfd/ft
100
Avg. benchmark
Avg. alliance
80
60
40
20
0
May July
Sept
Nov
Jan
Mar
May
1991
July
Sept
Nov
Jan
1992
1993
midyear, a project was designed to test the
abilities of the service companies to provide
cost-effective stimulation solutions. By the
beginning of 1993, the SBU had aligned all
pumping and wireline business with the
Schlumberger companies.
The alliance operates with a steering committee comprising the Amoco operations
manager, representatives from Dowell and
Wireline & Testing and the alliance coordinators. The role of the steering committee is
to set objectives and communicate results
between upper management and the working committee.
Most alliances have two coordinators—
one from the Amoco business unit and one
from the Schlumberger companies. The
coordinators are the facilitators for the
alliance, and also responsible for scheduling, quality assessment, a newsletter for
communicating results, interventions to
solve specific technical problems and
alliance scorecards—tools for measuring the
success of the alliance.
The SBU alliance is organized into four
alliance field teams, each composed of
Amoco, Dowell, Wireline & Testing and
GeoQuest people in the office and the field.
The teams select and evaluate wells, and
identify and modify processes for their local
operations from recompletion and fracturing
to plug and abandon.
Initially, there was redundancy in fracture
and recompletion evaluation and design,
with both sides performing the same tasks. A
streamlined approach was approved by each
side, and is now used in the alliance. Flexibility in job scheduling has resulted in better
utilization of equipment and personnel.
Comparison of well completion and fracturing costs tracked before and after formation of the alliance shows that the cooperative approach has reduced costs by 20%.
Accompanying the reduction in costs is an
improvement in well performance relative
to benchmark wells (left ).
Individual Excellence: Each company is strong
Information: Partners share data required to
Integrity: The partners behave honorably in
and has something of value to contribute. Motives
make the alliance work. These include objectives,
ways that justify and enhance mutual trust. They
for pursuing the relationship are positive—to pur-
technical data, and knowledge of conflict, trouble
do not abuse information, nor do they undermine
sue future opportunities, not mask weaknesses.
spots or changes.
each other.
Importance: The alliance fits with major strategic objectives.
Interdependence: The partners need each other,
Integration: Partners develop linkages and
shared ways of working together. They build broad
connections between many people at different lev-
have complementary skills and couldn’t achieve
els in the organization. They become both teach-
the same results alone.
ers and students.
Investment: Each side shows tangible signs of
Institutionalization: The alliance is given a for-
long-term commitment by devoting financial or
mal status, and extends beyond the people who
other resources to the relationship.
formed it.
1. Kanter RM: “Collaborative Advantage: The Art of Alliances,”
Harvard Business Review (July-August 1994): 96-108.
Daunis JR and Scott FL: “Division of Technology Ownership Between a Service Company and Customer,” paper
SPE 25843, presented at the SPE Hydrocarbon Economics
and Evaluation Symposium, Dallas, Texas, USA, March 2930, 1993.
35
36
Connection Time
200
150
Time, days
operating in West Texas, officially began a
pumping alliance with Dowell in 1992 covering cementing, acidizing and fracturing.
“Substantial savings have been realized and
pumping service quality has improved constantly,” reports alliance coordinator Fred
Ray of Amoco, in a recent alliance newsletter. “We attribute the savings and improvements to our commodity planning and process reengineering.” Since the alliance
began, the PBBU has documented a cost
savings of $1.3 million.
Among the greatest challenges in any
alliance effort are documenting and quantifying improvement, probably more difficult
in a service industry than in manufacturing.
One of the most powerful tools for recording progress is the scorecard, and the PBBU
alliance team takes scorecards seriously—to
the point of creating a team to evaluate
scorecards. Scorecards have been devised to
track all activities to understand problems,
identify bottlenecks and recognize improvement. Examples are scoring workover
cementing jobs in categories such as cost of
job, cement left in pipe, job pumped on
time and remedial cement required. Often
the best scorecards are the ones that look
bad, because problems can be tackled only
if they are discovered. And some of the
most successful scorecards are those that
are no longer used—either they have helped
identify other factors that should be tracked,
or the problems they’ve exposed have been
addressed.
The PBBU alliance operates through intervention teams to drive improvements to gain
efficiency. “Joint intervention teams are
highly focused to resolve issues in a timely
manner,” says Amoco Resource Manager
Ted Rolfvondenbaumen. “In other words,
we involve the right people at the right
time.” For example, in the past year, the
fracture appraisal intervention team has
reduced lost time per job from 50 to 32
minutes; replaced bagged sand with conveyed sand; switched to PCM fluid delivery;
scheduled multiple fracture jobs in one day;
reduced spillage to almost nothing; and
brought wells on production within an average of 4.5 days, compared to 51 days in
1993. These process improvements have
resulted in 17.6% cost savings for Amoco,
and 5.3% savings for Dowell.
A third alliance has developed with
100
50
0
1991
Amoco
1994
Industry
1994
Amoco
nReduction in connection time—from
well spud to product sales—for Amoco’s
Greater Green River basin.
Amoco’s Northwest Business Unit (NWBU).
The NWBU comprises six basins straddling
the Rocky Mountains in Colorado and
Wyoming. In 1993, the NWBU’s Greater
Green River basin group formed an integrated alliance to maximize value from the
remaining exploitation opportunities in a
20-year-old field. The alliance united the
efforts of Amoco, Dowell, Wireline & Testing, Exeter Drilling, Apex Mud and Cooper
Wellheads. Since then the agreement has
been extended to include three other fields.
The major objectives were to reduce total
system costs for drilling and completion,
reduce cycle time and continuously
improve service quality.
The alliance steering committee set incentives for recognition of innovative and superior work at three levels: individual, team
and company. To monitor progress, the
committee established measures—well performance, well cost, service quality, timing
and adherence to plan.
Total well costs in the first field dropped
49% compared to 1991 levels, an achievement made possible by numerous changes
in the drilling and completion process.
Amoco completely redesigned the wellhead
assembly, facilities and casing size to shave
costs. The drilling contractor improved the
drilling process to reduce average drilling
time per well by six days. Alliance partners
modified frac fluid and proppant, taking
advantage of the BRACKETFRAC technique
in which both buoyant and dense proppant
are injected to create artificial barriers
above and below the desired fracture interval, thereby controlling fracture height.
Dowell engineers used the FracNPV application that examined the balance between
fracture cost and anticipated production to
identify the most cost-effective fracture treat-
ment. Dowell supplied coiled tubing services to eliminate the need for a service rig
and exploited used coiled tubing as costeffective production tubing.
Fracturing costs per volume of gas produced have been reduced by an average of
57% compared with prealliance fracs. Connection time—time from spud to first sales
—dropped 66% (left ). News of the project’s
success has spread, and other operators in
the region have approached Amoco with
proposals to turn portions of their operations
over to Amoco to optimize production.
Alliances in Research and Development
Not all alliances between oil and service
companies revolve around field operations.
Collaboration and optimization of resources
are being taken a step further with research
and development alliances. Through such
alliances, the oil company benefits by
obtaining the tools and products for their
precise needs. In addition, the service company develops products that can be transferred to the market, and the companies
exchange know-how.
An example of such an alliance is the
collaboration between AGIP, the Italian oil
company, and Wireline & Testing and
GeoQuest. In 1992, Agip sought a working
relationship with a service company to
enhance the usefulness of dipmeter logs by
automating more of the interpretation and
integrating it with other log data. Agip
wanted more than a typical operator-contractor arrangement, in which the contractor programmers would meet Agip’s specifications: working together, geologists and
programmers from both sides created a
product adapted to user needs.
The project was named DipFAN for dip
facies analysis, and split into six modules.
For three of the modules, Agip engineers are
assuming the role of operator, taking the
project lead with responsibility for specification and design documents, executable
code and a user guide, while their Schlumberger counterparts take the role of partner.
For the other three modules, the roles
reverse. Four of the modules have developed to field-test stage, and work began on
the remaining two early in 1995. All six
modules will become part of the GeoFrame
oilfield data interpretation system (see “Tapping the Dipmeter,” next page ).
Another example of a development
alliance is the agreement between Statoil,
the Norwegian oil company, and Geco-
Oilfield Review
Tapping the Dipmeter
DipFAN facies analysis consists of software modules for faster, standardized interpretation of dipmeter data. By year end, six modules will be completed and running on the GeoFrame system.
Three of the modules have been completed: the
StatPack, FasTex and SediView applications.
The StatPack program is both a stand-alone
module and a statistical library used by the
other components of DipFAN. It performs basic
processing such as principal component and
cluster analyses.
FasTex processing conducts geology-driven pattern analysis of high-sampling rate resistivity data
from the dipmeter to extract layering, heterogeneities and fractures. Texture curves are generated by cluster analysis to define a high-resolution
electrofacies zonation. The program outputs a catalog of facies in the specified interval, and segments the interval into layers with those facies
(top, right).
SediView analysis processes dip information to
produce a sedimentological description of the
logged interval (bottom, right). The method first
■FasTex pattern analysis for clustering dipmeter data into a specified number of layers—five in this case.
The geologist can cross-plot variables such as volume, apparent thickness or contrast of conductive events
versus resistive events, to monitor the quality of clustering (left). The resulting vertical zonation is displayed
with representative examples of each zone, identified by their eight dipmeter channels (right).
requires making a link between lithological information and dip results. Then the structural dip is
computed and subtracted, to rotate the sedimentary bodies to their initial position. The final step
detects the boundaries and orientation of the sedimentary structures.
■SediView analysis of dip information to produce a sedimentological description of the logged interval.
Raw dip results (track 1) are processed to give local curvature axis (track 2). Structural dip is estimated from
stereonet projection (center) and subtracted from raw dips to yield sedimentary dips (track 4). Dip dispersion
analysis is reported (track 5) and the sedimentary structure is delineated (track 6).
37
the Norwegian oil company, and GecoPrakla to commercialize the SUMIC subsea
seismic acquisition and processing technique. The new system places four sensor
components on the ocean floor and records
signals from a conventional marine seismic
source. This allows recording of shear
waves, which have previously been
recorded only on land (see “Why Subsea
Seismics?” below ). Shear wave analysis
adds information about rock and fluid
boundaries that eludes conventional compressional-wave seismic interpretation.
Statoil had already invested years to
research the SUMIC technology, including
three feasibility studies, scaled experiments
and comparison of the sensors with reference sensors in controlled environments. It
was time to find a contractor to help commercialize the system.
After considering several companies, Statoil selected Geco-Prakla to develop and
improve the equipment and associated services, and promote marketing and sales. The
agreement permits Statoil to retain ownership rights on the technique, while Schlumberger has exclusive user rights. The agreement is one of a collection of projects under
a wider umbrella agreement with Statoil. In
a separate project for processing and interpretation, new functionality will be added
to the Charisma seismic workstation to handle the new type of data.
The Hard Road to Alliances
There are no short cuts to alliance success.
Process mapping can be a tedious exercise.
Meeting after meeting to explain total quality management and to ensure continuous
improvement can make office life more
demanding. The alliance approach requires
learning a new way to work, and it raises
some difficulties and questions. The foremost problem has been securing top-level
commitment and top-to-bottom buy-in to
the alliance concept. For alliances to work,
they must be part of the business plan, not a
passing fad.
An alliance is not a short-term fix. There
may be early successes that are not repeatable. Large cost savings encountered in the
first rounds of continuous improvement may
have caught what alliance specialists call
“no-brainers,” or “low-hanging fruit”—the
easy fixes that yield big savings. Later savings may be incremental, but still important,
and not attainable if the alliance partners
give up too quickly.
There is also a fear of change. People are
going to be concerned about their careers,
their power and their control. These very
delicate, significant issues must be considered before an alliance is formed. Restructuring is not a necessary outcome of an
alliance. According to Rick Adams, Operations Engineer for Mobil Exploration & Pro-
Why Subsea Seismics?
Conventional marine seismic surveys record compressional (P) waves but no shear (S) waves. This
Source boat
Recording vessel
is because the receivers are in seawater, and water
supports only P waves, no S waves. The new
SUMIC subsea seismic data acquisition technique
Source
plants four components of sensors—one
hydrophone and three geophones—on the seafloor.
■ SUMIC subsea
seismic acquisition, commercialized through an
alliance between Statoil
and Schlumberger. Sensors on the seafloor
record reflected compressional and shear waves.
Receivers coupled to the solid seafloor can acquire
both P waves and S waves that have been con-
P wave
verted from P waves upon reflection (right).
The acquisition of S-wave data may solve many
Receiver groups
problems encountered in conventional marine seismic surveys. Compressional waves are disrupted
by changes in fluid content, especially the pres-
S wave
ence of gas, in subsurface layers. That makes
detection of gas possible with P waves, but also
renders lithological changes invisible. Shear
waves ignore fluid changes and measure only rock
properties. Hoping to harness shear waves in this
and fluid type from subsurface layers. This appli-
way, Statoil conducted a feasibility study to illumi-
cation requires calibration with log data—incorpo-
nate the top of a reservoir through a gas chimney.1
rating P-wave and S-wave velocities for known
In zones where gas had completely obliterated
rocks and fluids—to extrapolate properties away
earlier P-wave signals, the seafloor sensor data
from the well using seismic velocities as guides.
showed reflections.
Shear-wave and P-wave data may also be combined to extract elastic properties such lithology
38
A third area of possible application of SUMIC
technology is hard seafloor. Seismic wave energy
ducing, in Midland, Texas, “Alliances are a
way of improving productivity without the
negative side effect of downsizing.”
Another potential concern is the fear of
being locked into an agreement and not getting the best technology. This must be taken
into account when choosing a partner. The
alliance partner that has offered the best
technology in the past and who offers it
today is likely to be the one who will be
able to offer it in the future.
Oil companies may question how big
they must be to have an alliance. According
to industry experts, alliances can work for
small independents as well as for majors.
The goal is to optimize assets, maximize
efficiency and lower total costs. An operator’s assets may be its infrastructure, or a
large in-house staff. Or it may have a small
in-house staff that needs to be augmented.
As more companies begin to make
alliances, some are looking for ways to
share their experience and to promote
alliancing as a new technology. Others are
beginning to view alliancing as a core competency, and are less inclined to share their
expertise. They have worked hard to learn
the skills, and are more reluctant to give
away their new competitive advantage. But
such an advantage may be temporary. New
business relationships that control total costs
and encourage constant change are healthy
for the industry, and give a direction for
more companies to follow.
Through alliances, operators and service
companies are trying to achieve a common
goal—lower the total cost per energy unit
produced. As more companies gain experience with alliances, significant savings will
continue to be made by both operators and
suppliers, and more opportunities will be
found for gaining efficiency and adding
value.
—LS
is greatly attenuated by reflection at large-contrast
boundaries. In conventional surveys, waves reflect
twice—going down, then up again—at the waterrock interface. Compressional- and shear-wave
recordings both may benefit from the placement of
receivers on the seafloor.
Finally, the new technology may facilitate
repeat surveys designed to monitor changes in
fluid saturation fronts. In the past, such surveys
have suffered from difficulties associated with
changes in acquisition geometry and equipment
and in processing methods between one survey
and the next. Permanently secured sensors may
alleviate some of those difficulties.
1. Berg E, Svenning B and Martin J: “SUMIC—A New Strategic Tool for Exploration and Reservoir Mapping,” presented
at the EAEG 56th Meeting and Technical Exhibition, Vienna,
Austria, June 6-10, 1994.
39
The DESC Engineer Redefines Work
John Baltz
Steve Bumgardner
Jeff Hatlen
Henry Swartzlander
Texaco Exploration and Production Inc.
Bakersfield, California, USA
Phil Basham
Al Blessen
Fred Sarrafian
Mark Schneider
Texaco Exploration and Production Inc.
Denver, Colorado, USA
Improved hydrocarbon recovery is the focus of the Production
Enhancement Group (PEG), which combines expertise from Schlumberger
Wireline & Testing, Dowell and Anadrill to develop a coordinated field
management plan. Their success depends on building new kinds of
working relationships between oil and service companies. Here is a look
at one of the most intimate of those relationships, the DESC Design and
Evaluation Services for Clients program. In this service, a Dowell engineer
works in the client office and with oil company engineers to analyze wells
that are candidates for production improvement and to develop treatments
Dennis Clayton
Tim Frank
Doug Gordon
Bill Taylor
Shell Western E&P Inc.
Houston, Texas, USA
Mitch Kniffin
Denver, Colorado
Fred Mueller
Bakersfield, California
Duncan Newlands
D.J. White
Houston, Texas
For help in preparation of this article, thanks to Larry
Behrmann, Schlumberger Wireline & Testing, Rosharon,
Texas, USA; Pierre Celle and Claude Vercaemer, Dowell,
Montrouge, France; Curtis Boney, Larry Brumit, Doug
Pferdehirt and Bobby Poe, Dowell, Sugar Land, Texas;
Anil Mathur, Jerry Richards and Grafton Withers, Dowell,
Houston, Texas; Bobbie Joines, Dowell, Denver, Colorado;
Jay Haskell, Wireline & Testing, Houston; Joe Mach,
Wireline & Testing, Sugar Land, Texas; Ken Nolte, Dowell,
Tulsa, Oklahoma, USA; Maripat Sexton, Texaco, Houston.
In this article, DART, DESC (Design and Evaluation Services
for Clients), FracIPR, NODAL and STIMPAC are marks of
Schlumberger; Unigraf is a mark of Control Data Corporation; VAX and VMS are marks of Digital Equipment
Corporation.
40
to enhance well productivity.
Mitch Kniffin arrives
at the Texaco office
in Denver at 7:00
in the morning,
wearing a Texaco
windbreaker with
“Star-Quality
Ambassador”
embossed on the
front. The jacket is a point of pride: he’s part
of a team recognized for saving the company
$38 million in drilling costs in the last two
years.
Kniffin sheds the jacket, grabs a notepad
and heads to the morning meeting. He joins
a half-dozen drilling engineers seated
around a teleconference phone discussing
the previous day’s well reports with Texaco’s
operations groups in Midland, Texas, USA
and other locations. The teams discuss good
news and bad, and debate solutions. When
the agenda turns to hydraulic fracturing in
West Texas, all eyes land on Kniffin.
On a typical day like this, follow Mitch
Kniffin around and you might conclude he’s
a hard-working Texaco engineer. There is little obvious evidence that he’s a Dowell
engineer, one of 95 assigned to client offices
in North America. By the end of 1995, an
estimated 175 engineers worldwide will be
assigned to customer offices in the DESC
program, short for Design and Evaluation
Services for Clients.
For both Dowell and operating companies
like Texaco, the DESC program provides significant benefits. DESC engineers are dedicated to serving a single customer, cutting
cost, improving quality and raising productivity. They contribute years of experience in
completion engineering, and when they
move into an oil company office, they are
practically self-sufficient, bringing their own
networked workstation, a bookshelf of
Dowell software and a modem. The oil
company provides an office with a desk and
chair, phone and electricity, and access to
well files and company experts.
The oil company gets a seasoned engineer
with a fresh perspective. Dowell gets a
Oilfield Review
Cementing Costs
Breaking Workplace Barriers
Given the sometimes adversarial relationships that formerly existed between service
and operating companies, placing a contractor in an oil company office may seem like
an unusual move. Yet, the idea is not new. In
Schlumberger, three notable incarnations of
this strategy foreshadowed the DESC program. In the 1960s, Schlumberger engineers
were placed in customer offices to operate
the complex DART radio log transmission
network, which conveyed data to the mainland from rigs in the Gulf of Mexico.1 In the
early 1980s, log interpreters were installed in
client offices, operating the VAX-based
Client Log Interpretation Center (CLIC). This
evolved into the third incarnation, the PCand workstation-based Dedicated Client
Center of today.
In the DART and CLIC programs, the relationship between contractor and operator
did not change. Where you worked
Summer 1995
60
Benchmark costs
Alliance costs
Thousands of dollars
50
40
30
20
10
Benchmark average – $28,580
Alliance average – $20,622
0
May
July
Sept
Nov
Jan
Mar
May
July
Sept
Nov
Jan
■Reduction in total
process cost is central to the DESC program. In east Texas,
DESC engineers
working in an
alliance with the
operating company
helped reduce the
cost of cementing
and fracturing. This
was accomplished
mainly through use
of software tools for
stimulation optimization, reduction in
standby equipment
and optimization of
fluids engineering.
Fracturing Costs
500
Benchmark costs
Alliance costs
400
Thousands of dollars
richer understanding of client needs and
improved access to opportunities for well
treatment services. Both parties benefit from
daily contact that builds trust, which stimulates the cross-pollination of ideas. This candid exchange results in easier acceptance of
new ideas and faster development of solutions. As management consultants say, it’s a
win-win scenario (right ).
Five years have passed since Bob Fagan
became the first Dowell engineer posted in
a client office, at Chevron in Bakersfield,
California. In the short time since its inception, the DESC program has grown quickly
and evolved to meet changing market
demands (next page). Here is a look at how
the DESC program works, and a tour of case
studies—in Texaco and in Shell—to see
how DESC engineers operate day to day.
300
200
100
Benchmark average – $245,148
Alliance average – $195,605
0
May
July
Sept
Nov
Jan
Mar
May
changed, but not usually how you worked.
The contractor mainly operated a system for
the client and fulfilled client requests on a
per-bid basis. Placement of the engineer
and equipment in the oil company office
was for expediency and took place within
the constraints of a conventional contractual relationship. There were happy coincidences of the supplier consulting to the oil
company, but that was not part of the plan.
The relationship between the two companies was generally maintained at the traditional arm’s length.
July
Sept
Nov
Jan
In the early 1990s, the DESC program
redrew the boundaries of that relationship.
Rather than work on a contractual basis,
the DESC engineer would look for wells
that could be more productive, and
1. Eaton FM and Decker GJ: “Digital Transmission of
Well Logs by Radio and Telephone,” Journal of
Petroleum Technology 18 (February 1966): 151-154.
41
Bob Fagan
becomes first
Dowell engineer
placed in an
oil company
office–Chevron,
Bakersfield,
California, USA.
Engaged mostly in
logistical planning
to boost service
efficiency.
Formal training
begins for DESC
engineers.
The term
DESC Design
and Evaluation
Services for
Clients coined.
1990
# of DESC engineers
Equipped with
VMS-based
workstation, 2400bit-per-second
(bps) modem,
CADE programs,
spreadsheet, word
editor, Unigraf
graphics package.
1991
Qualifications
defined for
Dowell engineers
posted in client
offices.
Ten engineers
placed in client
offices, all at
Dowell initiative.
Twenty DESC
placements.
Bernard Fraboulet
becomes first
DESC engineer
outside North
America, for Elf in
Pau, France.
1992
DESC program
refocused on
identifying candidate
wells for remedial
treatment to increase
productivity,
called candidate
recognition.
Systems Analysis
Module ( SAM )
introduced,
computerized
prediction of well
performance.
Clients start
asking for DESC
engineers.
DESC engineer
candidates begin
3- to 6-month
training with the
Performance
Enhancement
Group ( PEG ) in
Houston.
Industry-wide
interest increases
in total quality
management
strategies.
VMS
First Wireline
engineers coplaced with DESC
engineers for
enhanced service
integration.
DESC toolbox
expanded to include
program to calculate
return on investment
of remedial
treatments.
1993
Oil companysupplier alliances
start to become
reality.
Schlumberger
gains full control of
Dowell, acquiring
the remaining 50%
of DowellSchlumberger,
ending a
successful 33-year
joint venture with
Dow Chemical.
1994
Dowell begins shift
from VMS-based
workstation to
PC platform, with
transition of
CADE programs.
Expansion in DESC
placements both
driving and driven by
growth in alliances.
1995
Strong growth of
alliances: 16 of
Dowell’s 20 largest
clients engaged in
some type of
alliance.
Introduction of four
new programs to
accelerate candidate
recognition from ~2
days per well to 1/2
day.
Dowell PhDs at
area level provide
high-level technical
support.
DESC engineers
connect to
Schlumberger
network using
14,400+ bps modem
and Internet
protocol.
200
150
PC
2100
Worldwide
rig count
1900
100
1700
50
DESC engineers
1500
0
Worldwide rig count
Rig count in North
America reaches
lowest level in 40
years.
■Time line of DESC program evolution.
develop strategies to bring them up to full
potential. This approach, called candidate
recognition, would increase opportunities
for Dowell that were independent of the
shrinking rig count, and would enhance
productivity for the oil company.
At this time, the idea of a service company representative posted in the office was
anathema to many oil companies. Yet, with
the advent of total quality management
(TQM), the DESC program offered an addi-
42
tional engineer to focus on finding low-cost
means of enhancing productivity. Many oil
companies were ready to consider this new
way to do business.
For the early DESC engineers, candidate
recognition was not the sole activity. The
first opportunities were improving the logistics of well treatment. This involved collaborating with the drilling or production department to better coordinate Dowell crews,
equipment and delivery of raw materials.
Small improvements in logistics yielded
large gains in productivity. For example, better scheduling can allow a crew to perform
two jobs per day instead of one, or can take
advantage of a crew that is 20 miles [32 km]
from the well instead of 200 miles [322
km]. Early in the DESC program, it became
clear that simply having a DESC engineer in
house significantly improved logistics to the
benefit of both Dowell and its clients.
Until about 1992, logistics remained a
key activity for the handful of DESC engineers. By the end of 1992, the focus shifted
to emphasize candidate recognition, which
today remains the core of the program
(next page, middle ). This umbrella covers
the range of pumping and fluids engineer-
Oilfield Review
being regarded as a guest to being accepted
as one of the team. Foremost, the engineer
must be able to work within the oil company culture to develop support for optimal
solutions.
“When I first arrived at Shell,” Newlands
said, “the most skeptical production engineer was the first to let me design a frac
job. When that job went off without a
hitch, that went a long way to winning the
trust of everyone.”
To build the range of needed skills, most
new DESC engineers receive three to six
months of training in the Production
Enhancement Group (PEG) in Houston. The
PEG comprises specialists from Wireline &
Testing, Dowell and Anadrill, who identify
wells with potential for increased production and develop an integrated program to
raise well productivity. Client interest in
PEG projects is funneled through Schlumberger sales engineers throughout North
America. PEG engineers then review client
well files and submit bids for well treatment
based on the analysis.
In the PEG program, Dowell engineers
learn the essentials of well performance sim-
Production rate
ing services, including fracturing, sand control, coiled tubing services, acidizing,
drilling fluids and cementing. In 1995, as
Schlumberger Wireline & Testing engineers
are being located in client offices along
with Dowell engineers, the umbrella now
includes log input to completion services.
Candidate recognition is expected to grow
in importance in mature markets, as operators seek to extend the life of aging fields.
With candidate recognition as the focus, a
new contractor-operator relationship had
been cemented (bottom ). “In the old way of
working,” said Duncan Newlands, a DESC
engineer for Shell Western E&P in Houston,
“the client might say, ‘Here’s my pump
schedule. Be ready
to roll Tuesday
morning at 5.’ Now
the client might
say, ‘ Work with
our
team
to
develop a completion plan for this
well that gives both
companies the highest value.’ Oil companies are beginning to realize there’s benefit
in trusting us to meet or exceed their criteria
for job performance.”
Given the large scope of responsibilities
the DESC program places on Dowell engineers, training had to rise to the challenge.
The DESC program starts with engineers
who have mastered the basics. Those picked
for the program typically have had at least
three years of experience in completion and
fluids engineering and have demonstrated
both entrepreneurial spirit and interpersonal
skills. These skills are essential, since the job
requires technical proficiency, business acumen and diplomacy. When first installed in
the client office, the engineer must win the
confidence of oil company colleagues and,
to be most effective, must progress from
Gap
Potential calculated
with SAM and
FracIPR software
Actual
Time
■Closing the gap. Candidate recognition
involves first identifying underproducing
wells and, using software tools like the Systems Analysis Module (SAM) and FracIPR,
calculating what the well could produce.
Second, well treatment strategies are
developed to “close the gap” between
what is and what could be.
ulation and candidate recognition. This
includes development of proficiency with
NODAL production systems analysis and
other Dowell software used in candidate
recognition. It also includes training in perforation, pressure transient and decline curve
analyses, fracture theory and fracture fluids
engineering.
The engineer then is posted to an oil company, usually in the production or drilling
department, and begins gradual assimilation. Three case studies show how DESC
engineers work today—two in Texaco, in
the context of a single-vendor alliance, and
one in Shell, in a more conventional relationship (see “Alliances in the Oil Field,”
page 26 ).
DESC in an Alliance: Texaco
Texaco has undertaken a significant change
that involves not only the sale of assets and
refocusing on core businesses, but a dramatic culture shift. This shift accelerated
with the 1994 launch of a worldwide plan
for growth, with a top-down emphasis on
TQM—a focus on continuously examining
how things are done and taking steps to find
better ways, including different ways of
working with contractors.2
“Historically, we placed a great deal of
emphasis on the lowest possible bid,” said
John Baltz, Texaco’s assistant division manager in Bakersfield. “All that changed when
we stopped focusing on price alone and
placed more emphasis on the significant
few oil and gas fields, technologies and relationships that contribute to performance.”
Five years ago, service companies were
2. For a review of TQM principles and application of
those principles in the oil field:
Burnett N, Harrigan J, Jeffries J, Lebsack T, Mach J,
Mullen D, Pajot D, Rat F, Robson M, Theys P and
Wohlwend H: “Quality,” Oilfield Review 5, no. 4
(October 1993): 46-59.
DESC Engineer Main Responsibilities
•Work with client on treatment design
and evaluation
•Collect and evaluate data for candidate
recognition treatment design
•Identify, coordinate and implement
treatment or design changes for
improved well performance and
economics
Summer 1995
•Collect and evaluate post-treatment data
(performance versus expectations)
•Provide benchmarks for continuous
improvement
•Document results and supply benefits to
the client and to Dowell technical support and management
•Enlist appropriate technical support
when necessary
•Identify and implement process
improvements with client
•Develop general knowledge of
Schlumberger product lines outside
Dowell
•Identify, coordinate and implement additional Dowell services and additional
Schlumberger product lines based on
client needs.
43
6
Time on location, hr
5
4
3
2
1
0
Sept
Oct
Nov
Dec
1993
Jan
Feb
March
Sept
Oct
1994
■Resource optimization means less time per treatment job. At the beginning of the
Texaco DESC program in Kern River, Texaco engineers would call for service early
because time management was not a priority. As a result, the pumping crew might
spend at least five hours at each job, sometimes just waiting to get in the hole. Mueller’s
close relationship with Texaco colleagues allowed him to work with them to improve
scheduling and remove bottlenecks and redundancies. “Once Texaco learned how much
time the pumping crews needed,” he said “and that time was a key element in our profitability, Texaco worked toward just-in-time pumping.” This cut time at the wellsite from
five to four hours per job, allowing crews to perform more jobs per day.
■A virtual Dowell
research center.
Jorge Manrique of
Dowell (left) and
Fred Mueller, confer
on Manrique’s modeling in Kern River to
understand steamflood efficiency—the
amount of energy
required to produce
one barrel of oil.
Manrique, a PhD
engineer with
Dowell in Denver,
is working with
Mueller and
Texaco colleagues
in Bakersfield.
viewed guardedly and kept at a distance.
Today, many suppliers have offices in Texaco facilities and work shoulder to shoulder
with Texaco colleagues.
Texaco has moved aggressively into
numerous alliances with key suppliers.
Texaco and Dowell entered into a US
pumping service alliance on March 1, 1995,
for all of Texaco’s cementing and stimulation needs.
“An alliance is more than just a singlevendor contract with an attractive price,”
said Fred Sarrafian, assistant division manager for Texaco in Denver. “It means that we
44
work together to drive down each other’s
cost and improve productivity. Both parties
share in the risks and rewards. In other
words, it has to have an alignment of goals
that motivates both parties to commit to
continuously improve how they work.”
Two examples of DESC engineers providing different kinds of service for Texaco are
in the Kern River field, of Bakersfield, California, and the Permian Basin of West Texas.
In both places, DESC service started within
a local alliance. These have evolved into a
Texaco-Dowell pumping alliance covering
all the US.
Texaco: Extending the Life of the Kern
River Field
Fred Mueller started as a DESC engineer for
Texaco in 1993, working in the Kern River
field in an alliance exclusive to Texaco’s
Bakersfield division ( next page, bottom
right ). Mueller is engaged in three main projects—resin packs, research on how
hydraulic fracture design affects steamdrive
efficiency, and optimization of resource
utilization (left and
below left ). The
foremost technical
challenge, and work
that occupies most
of his energy, is the
resin pack. An
overview of Kern River production engineering shows why this is a priority.
The Kern River field has some of the tightest margins in North America. The oil is
heavy and requires steamflooding for production, which averages less than 20 barrels of
oil per day (BOPD) per well. Still, the field is
advantaged because productive intervals are
typically less than 1500 ft [460 m] deep, and
oil saturations are high. Texaco, the largest
operator in the field, produces more than
80,000 BOPD from 4600 wells. The 96-yearold field is the fifth largest in the United
States, with estimated reserves of 518 million
barrels.
The largest operating expense for Texaco
is making steam, which runs $80 million a
year. Extracting the most oil per calorie of
gas burned to make steam—called the fueloil ratio—is the most important driver of
efficiency.
After personnel costs, the next driver is
contract work expenses. The bulk of contract
work—and here’s where resin packs come
in—is removal of sand. Texaco walks a thin
line between sand production and steam
injection. Too much steam, and wells sand
up prematurely. Too little steam, and wells
don’t produce efficiently. Even at the right
balance, 2 to 3 tons of sand are produced
per day, adding up to an expensive problem.
If sand production can be stemmed, then
Texaco can achieve two objectives: cut costs
related to sanding, and deliver the optimal
steam injection rate to achieve the highest
possible fuel-oil ratio.
Curbing sand production with gravel packs
and slotted liners provided mixed results. In
1993, Mueller recommended a STIMPAC service—fracturing combined with gravel pack-
Oilfield Review
■Rigging up in the
land of the eightminute frac. Producing wells are fractured and packed
with resin-coasted
sand in the Kern
River field. The frac
jobs are small,
pumping 10,000 to
25,000 lbm [4535 to
11,340 kg] of proppant to produce
fracture half-lengths
of 50 to 100 ft [15 to
30 m]. Texaco wells
follow a “five-spot”
pattern: one injector
surrounded by four
producers.
■The Kern River skirts
the southern edge of
the Kern River field in
Bakersfield, California.
■What phenolic resin coating does to
proppant. This pack of sand is held
together by heat-induced fusing of a phenolic resin. It has a permeability in the
darcy range, and enough mechanical
strength to hold back the flow of sand at
typical production rates.
Summer 1995
ing. The treatments halted sand production
without restricting the flow of oil. At the
same time, Steve Bumgardner, a Texaco
petroleum engineer, introduced the more
economical idea of using resin-coated sand
to control formation sand production.
A resin pack involves filling a hydraulic
fracture with resin-coated sand. The resin, in
this case a phenol, is activated mainly by
the 220°F [104°C] downhole temperature.
The fused resin binds the coated sand grains
into a solid but high-permeability pack that
stops sand production (above, far left and
top ). Uncoated sand would not work in
Kern River because low closure stress of the
shallow wells would not hold the sand in
place. Also, the high viscosity of the crude
would drive uncoated sand into the well.
While posted in the Rocky Mountains,
Bumgardner had worked with resin packs.
“Fred and I bounced around ideas for
designing resin packs for Kern River,” Bumgardner said. Texaco and Dowell worked
45
as
he
ort
Sh
Di
ab
lo
Pl
km
120
0
miles
75
Texas
■Texaco properties,
leased and owned,
in the Permian
Basin of New Mexico and West Texas.
The Permian Basin
occupies about the
same area as the
Irish Republic.
at
f
m
or
O
0
Midland
Basin
in
Bas
tral rm
CenPlatfo
Delaware
Basin
N
IC
46
n
ter
X
More than one third of the hydrocarbons
produced in the United States since the
1920s has come from the 29,000-squaremile [75,100 km2] area of West Texas and
southeast New Mexico called the Permian
Eastern
Shelf
elf
New Mexico
E
Texaco: Fracs in the Permian Basin
UNITED STATES
M
together to optimize the treatments, looking
at sand size, resin type, pump schedule and
fracturing fluids.
Proof came at the end of 1994. In a 12well pilot study, 10 wells were improved.
Average production per well rose from 16 to
27 BOPD, and monthly cost of well servicing dropped from $1549 to $540—a 70%
increase in production and a 65% reduction
in maintenance cost. The two wells that did
not improve failed uphole, not in the treated
zone. Based on these results, the Bakersfield
division plans to perform resin packs in 170
wells this year.
The key to success of the process was the
collaboration of Bumgardner and Mueller.
“My expertise is in fracturing technology,”
Bumgardner said, “but I don’t need to know
the exact fluid compositions and equipment
characteristics. Combining my expertise
with Fred’s knowledge and experience in
fracturing and pumping made for the most
effective team.”
“We used to try to be the expert in everything,” said Henry Swartzlander, a Texaco
operations manager who oversees about
half of Texaco’s Kern River assets. “This ultimately hurt our profitability because we
didn’t have the time, people and competency to excel at everything. Having people
like Fred here allows us to tap the worldwide expertise of Dowell, which reduces
our cycle time by shortening our learning
curve. Ultimately, faster cycle time improves
our profitability.”
A key to improving cycle time for Texaco
is daily give and take with Mueller that
increases knowledge of available technology. Another means is Mueller’s lunchtime
seminars on a variety of well and fluids
engineering topics, such as cementing, fracturing high-permeability reservoirs, sieve
analysis and basics of cement additives.
“The ultimate test of the success of this
program,” said Jeff Hatlen, a Texaco operations manager in Kern River, “is improved
profitablity of both companies. My interests
are not limited to reducing costs. I’m interested in developing opportunities and making more money. If Dowell can help me do
that, I’m willing to share that success.”
Marfa
Basin
Southern
Shelf
a-Marathon
Ouachit
S
Basin (above ). The region has yielded 30
billion of the 87 billion barrels of oil produced in the United States in 70 years. Production today is 38,000 barrels of oil equivalent (BOE) per day, and although it is
declining slowly, it is still the most prolific
area outside of Alaska.3 Proved reserves are
5.4 billion BOE.
The Permian Basin is a hodgepodge of
depositional environments, including reefs
and shelf carbonates, turbidites, beach and
nearshore sands and sabkha.4 Well productivity is 20 to 100 BOPD, with the typical
well making 35 BOPD. Texaco conducts
one of the most active drilling programs in
the basin, and operates some 15,000 wells.
Following the diversity of depositional environments, well depths vary from 3500 to
28,000 ft [1066 to 8534 m]. About half of
Texaco’s production is from carbonates, and
the bulk of work for DESC Engineer Mitch
Kniffin centers on fracturing tight dolomite
oil and gas reservoirs.
Fracturing is big business for Texaco in the
Permian Basin. In 1994, the company fraced
200 wells—with up to three fracs per
well—and if the pace of drilling holds, the
number may rise to 250 this year. With one
well fraced every two days, Kniffin monitors
the progress of about 30 wells at one time.
From the Texaco division headquarters in
Denver, Kniffin works with engineers in
both Denver and Midland who oversee the
Permian Basin operations. He knows both
Val Verde
Basin
truc
tur
a
lB
elt
groups, having started as a Texaco DESC
engineer in Midland in 1992, before moving
to Denver in 1994.
Along with fracture design, Kniffin also
has been coordinating evaluation of methods to find the optimal fracturing program.
For this challenging area, what works in one
well, may fail in another well that appears
to have identical properties.
The main challenge is avoiding near-wellbore screenout: bridging of proppant in the
fracture near the wellbore, which halts fluid
entry and propagation of the fracture. Wellbore screenouts can occur in the complex
connection between the wellbore and fracture entrance (next page top ). This complexity, called tortuosity, generally results from
too large an angle between the perforation
and the plane of the natural fracture, or from
multiple fractures that may or may not coalesce into a preferred single fracture (next
page bottom ). Coalescing of fractures is
likely to produce tortuosity when perforations are not aligned with the principal
stress in the formation. Multiple fractures
produce narrower fracture channels and
more surface area for fluid loss through the
fracture faces. Both coalescing and multiple
fracs increase the likelihood of proppant
accumulation near the wellbore and a resulting screenout. Reducing fracture entrance
Oilfield Review
n
um tio
im ec
ax ir
M ss d
e
str
n
um tio
im ec
ax ir
M ss d
e
str
Path of fracture
Perf
Perf
angle > 30°
Path of
fractures
0°< angle <30°
■Near-wellbore restrictions that contribute to screenout. A goal of
perforation and fracturing design is to minimize tortuosity of the
connection between the perforation and the fracture, and thereby
develop fractures with the highest possible conductivity. Modeling
studies show that fractures typically extend from the base of a
perforation at the cement-formation interface and travel some distance around the wellbore to reorient into the plane parallel to the
maximum horizontal stress. A main concern is the development
of multiple fractures, which produce flow restrictions that lead to
screenout. Experimental evidence suggests that multiple fractures
tend to form when the angle between the perforation and maximum stress direction is greater than 0° but less than 30°.
Rhomboids
■Coalescence of fractures as a cause of tortuosity. How fractures evolve from perforations
can contribute to pressure drop, and proppant bridging, in the region near the wellbore.
As fractures propagate, they may form an overlapping arrangement, called en echelon,
and eventually connect. Isolated rhomboids of rock develop between the connecting tails
of the fractures. Small fractures associated with these rhomboids are suspected to contribute to the pressure drop that leads to early bridging of proppant. Limiting the height
of the fractured interval is thought to reduce the number of rhomboids, and thus the
mechanism that leads to bridging.
effects is required for proppant to flow unimpeded, and for the fracture to reach maximum length and conductivity (see “Getting
the Most from Perfs,” next page ).
Kniffin works with Texaco engineers to
determine optimum fracture dimensions and
develop a treatment pumping schedule,
contributing to Texaco’s saving at least one
engineering day per frac design. He tracks
the performance of treatments to discern
patterns that lead to success or failure. This
is a critical step, since process improvement
is integral to the success of the alliance.
Summer 1995
With up to four jobs per week, Kniffin
can’t attend each one. For critical jobs, he
relies on a double cellular phone connection between his office in Denver and the
Dowell crew at the wellsite in West Texas.
One line provides a voice connection. The
other furnishes real-time, on-screen monitoring of up to 10 variables during the job,
typically including pump rate, surface pres-
sure, fluid density and additive composition
and concentrations.
“As our engineers focus more on well
planning, they still collaborate on treatment
design,” said Phil Basham, a Texaco drilling
team leader. “But I see Mitch taking a larger
role in designing and managing jobs. We
are more productive if we rely on Dowell
for job execution and have our people concentrate on well planning, process improvement, cost reduction opportunities and technology applications.”
Adding responsibility and accountability
to a contractor has “broken down our
paradigms,” said Al Blessen, Texaco drilling
engineer. “Now we want to find the best
practices, rather than those that we have
always relied on and are comfortable with.”
An example of a paradigm break was in
Texaco’s design of Permian Basin completions. Texaco’s practice was to complete
wells using three strings of casing: surface,
intermediate and production string. This
approach was perceived to minimize risk of
loss of well control from lost circulation or
water entry (right ).
3. Permian Basin Petroleum Association, Midland, Texas,
USA, personal communication, May 1995.
4. Sabkha encompasses depositional environments just
above the high-tide line in an arid setting. It includes
evaporites, tidal flood and eolian deposits.
47
Texaco engineers looked for a new
method and worked with Kniffin to design
lightweight cementing techniques that
allowed elimination of the intermediate
string. Lighter fluids permitted cementing
the production string in one stage or, if very
long, in two stages.
Taking this approach required that Texaco
accept the risk of lost circulation and water
entry during drilling. Managing this risk,
however, or even repairing damage done by
water entry, is less costly than setting intermediate casing. Texaco has used the procedure on select projects since 1992, saving
10 to 15% on each well.
“It allows us to drill in places where we
could not have afforded to drill otherwise,”
said Phil Basham. “Every nickel saved got
reinvested in a new well. That’s the kind of
benefit we’re after.”
Shell Western E&P: High-Pressure
Coiled Tubing
South Texas presents Shell Western E&P Inc.
with some of the company’s most challenging gas wells. They are deep, hot, geopressured and sometimes sour. In the Rio
Grande Valley, Shell produces 450 million
cubic ft of gas and condensate per day from
about 350 wells. The main technical challenge is beating the decline curve of the
wells—the fall in productivity over time—by
lowering the cost of production and producing hydrocarbons as fast as possible.
Duncan Newlands, Shell’s Houstonbased DESC engineer, addresses this challenge by splitting his time between fracture
work and coiled tubing services. His contri-
Three-string
Two-string
Surface
Stage 2
cement
■Three- and twostring completions.
Applying lightweight mud and
cement, Texaco
saved about 10 to
15% on each completion by deleting the
intermediate string.
Intermediate
Stage 1
cement
Production
butions to fracture design have increased
Dowell’s share of jobs and enhanced efficiency for Dowell and productivity for
Shell. His contribution to an innovative
application of coiled tubing for workovers
helped save Shell $1 million in 1994 and
expanded Dowell’s coiled tubing services
in the region.5
Coiled tubing is used to clean out sand
plugs inserted during multistage massive
hydraulic fracturing. In this fracturing technique, the bottom zone is fractured first,
then the interval is filled with sand to isolate
it, and the zone above is fractured. The second zone is then filled with sand, and the
zone above that is treated, and so on up the
hole. After the final fracture, the column of
sand, which may reach a thickness greater
than 1000 ft [305 m], must be removed to
commingle production from all the zones.
Getting the Most from Perfs
To minimize entrance effects and maximize
fracture conductivity, Kniffin and a team of
Texaco engineers are trying a combination of
five techniques:
■Electronics Technician
Walter Limpias with gel
pumped on a typical
Kern River frac job.
• Larger-diameter perforations. Historically, holes
were commonly of small diameter—typically
0.35 in. [0.9 cm] or smaller. Larger-diameter
perforations—0.5-in. [1.3 cm] and larger—are
thought to result in a more direct path from perf
to fracture.
48
Oilfield Review
at a depth of 12,000 ft [3658 m]. Because
only 30 ft can be “snubbed” at a time,
removal of the column of sand can take 7 to
12 days.
A team of Shell and Dowell engineers
investigated the practicality of adapting
existing coiled tubing and surface equipment to cope with the high pressures. They
found that conventionally available 11/4inch, thick-walled coiled tubing provided
the best of all possible properties: strong
enough to safely endure the wellhead and
downhole pressures, large enough to
accommodate pump rates for efficient
cleanout, and having an acceptable fatigue
life, given the high operating pressure.
Two pieces of equipment had to be
adapted. First, the high pressure at the wellhead made buckling of tubing at the stripper a concern. To combat this, an antibuckling guide was utilized to provide lateral
support and minimize the distance between
the stripper and chains that drive the tubing
in and out of the injector. Second, a
15,000-psi blowout preventer and stripper
were built to improve the economics, safety
and speed of the coiled tubing job. Yard
tests at operating pressures showed the new
equipment could perform several cleanouts
before a string of coiled tubing would have
to be retired to conventional work.
Since 1994, the technology has been used
to perform more than 75 cleanouts, each
Rick Prudhome
With wellhead pressures sometimes
approaching 10,000 psi, snubbing units
were used to remove sand, since conventional coiled tubing units can accommodate
wellhead pressure only up to 3500 psi. A
snubbing unit is a combination of pressure
control and pipe handling equipment
(below ). The equipment jacks pipe through
the pressure control equipment 30 ft [9 m]
at a time. When at the required depth, gel is
pumped down the pipe to circulate sand to
the surface. The typical south Texas well has
a producing interval of at least 200 ft [60 m],
■Removing sand with a snubbing unit (top) and a coiled tubing unit with new high-pressure surface control equipment. The snubbing unit is about 70 ft [21 m] high, and
requires personnel working at the top, which is a significant safety risk. Removal of sand
in a south Texas well takes about one week with a snubbing unit but can be performed
with a coiled tubing unit in fewer than three days, and at a lower safety risk.
• Tighter phasing of perforations. Decreasing the
phase angle of perforations maximizes the
• Maximized pad fluid viscosity. A pad is the first
fluid pumped during hydraulic fracturing, and
likelihood of a perforation aligning parallel to
generally does not contain proppant (previous
the fracture plane. At the ideal alignment, frac-
page, bottom). The more viscous the fluid, the
tures tend not to split into multiple branches,
wider the fracture; it also makes the job more
minimizing the number of restrictions that lead
costly because of the requirement for added
to screenout.
• Proppant slugging. This process involves early
pumping of small, intermittent volumes of proppant slurry (slugs) with progressively higher
densities of proppant.1 These slugs are thought
horsepower and for breakers, chemicals that
reduce viscosity after pumping. Optimal viscosity balances added cost against higher fracture
5. Van Adrichem WP, Gordon DG and Newlands DJ:
“Development and Utilization of a Coiled Tubing
Equipment Package for Work in High Pressure Wells,”
paper OTC 7874, presented at the 27th Annual OTC
Meeting, Houston, Texas, USA, May 1- 4, 1995.
1. For more on near-wellbore tortuosity and proppant slugs:
Cleary MP, Johnson DE, Kogsbøll H-H, Owens KA, Perry KF,
de Pater CJ, Stachel A, Schmidt H and Tambini M: “Field
Implementation of Proppant Slugs to Avoid Premature
Screen-Out of Hydraulic Fractures with Adequate Proppant
Concentration,” paper SPE 25892, presented at the SPE
Rocky Mountain Regional/Low Permeability Reservoirs
Symposium, Denver, Colorado, USA, April 12-14, 1993.
2. Stadulis JM: “Development of a Completion Design to Control Screenouts Caused by Multiple Near-Wellbore Fractures,” paper SPE 29549, presented at the SPE Rocky
Mountain Regional/Low-Permeability Reservoirs Symposium, Denver, Colorado, USA, March 20-22, 1995.
conductivity.
• Limiting the height of the perforated interval,
to plug off minor fractures, diverting more of
called point-source perforating.2 Perforating
the proppant to the major fractures, improving
only a limited height, usually in the middle of
their conductivity.
the interval of interest, reduces the number of
multiple fractures and increases the likelihood
of them coalescing into fewer, larger fractures.
Summer 1995
49
taking 1 to 3 days to complete at about half
the cost of a conventional snubbing unit.
There has been interest in expanding the
technique to fields in the Gulf of Mexico
and the Middle East.
“Duncan’s main contribution in this project was as an enabler,” said Bill Taylor, well
servicing team leader for Shell. “Because
he’s immersed in our business, he knows
our needs, and is able to bring together the
key Dowell experts to meet the challenge.
You walk around this office and you hear a
lot of ‘Duncan said —.’ That means his fresh
perspective is bringing us results.”
What Comes Next?
Once a DESC engineer is installed in an
operating company, gains the client’s trust
and knowledge of the client’s needs, works
to continuously reduce cost and build productivity, what comes next?
It varies with the company. For some, like
Shell Western, it means adding another
DESC engineer. In the Houston office, a second DESC engineer will focus exclusively
on candidate recognition, allowing Duncan
Newlands to concentrate more on process
reengineering and optimizing fracture design.
At Texaco, prior to the nationwide alliance,
the seven DESC engineers in Texaco offices
provided solutions specific to the geographic area served by those offices. With
the formation of the nationwide alliance,
there is a trend away from using the DESC
engineer as only a local solution. Now 11
Texaco DESC engineers pool knowledge
with their respective local Texaco colleagues to spread best practices throughout
the organization. “Not only do we want to
drive out redundancy and boost production
in Kern River,” said John Baltz of Texaco,
“we want to align on process and process
analysis everywhere. That is a driver of our
financial success.”
Both Texaco and Shell have seen the role
of the DESC engineers expand as they prove
their expertise, and as the operating companies gain trust to delegate more work. This
means the definition of candidate recognition widens to encompass not only obvious
underproducing wells but to include application of new technology and techniques to
boost production in wells already considered to be doing their best. Finding candidates for new technology, like the south
Texas wells cleaned with high-pressure
coiled tubing, will build business for Dowell
while cutting cost and boosting productivity
for operating companies.
New technology also includes new tools
for candidate recognition. To this end, several reservoir engineering analysis programs
have recently been added to the DESC engineer’s toolbox. These tools let the DESC
engineer evaluate the current condition and
potential of more wells with greater speed
and ease. This ultimately leads to faster
identification of opportunities and earlier
enhancement of well productivity.
“To make this program grow productively,
the most important element is encouraging
the Dowell engineer to focus on client
objectives,” said Jerry Richards, Dowell vice
president. “I can’t overemphasize the importance of that. It is the key to growing our
business and the customer’s business, which
is the purpose of the DESC program.”
—JK
Who they are
50
Mitch Kniffin
Duncan Newlands
Fred Mueller
• Texaco DESC engineer, Midland,
Texas, 1992; Denver, Colorado, since
October 1994.
• Seven postings in sales, engineering
and management, in North Dakota,
Kansas, Louisiana, Oklahoma and
Texas.
• Hired with Dowell in Gainesville,
Texas, 1979.
• BS degree in chemistry, Kansas State
University, 1979.
• Shell DESC engineer, Houston, Texas,
since May 1994.
• Two years as a sales engineer in
Houston, preceded by two years as a
training instructor at Dowell’s
Kellyville (Oklahoma) Training Center,
and three field assignments in the
Rocky Mountains.
• Hired with Dowell in Gillette,
Wyoming, 1987.
• BS degree in geology and BS degree in
petroleum engineering, Texas A&M
University, 1986.
• Texaco DESC engineer, Bakersfield,
California, since September 1993.
• Five positions in marketing, engineering and sales, preceded by assignments in three field locations in south
Texas and the North American midcontinent.
• Hired with Dowell in Bryan, Texas,
1980.
• BS degree in engineering technology,
Texas A&M University, 1980.
Oilfield Review