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SPE-171796 Wintershall’s DCI

Applications of Wintershall’s Drilling Complexity Index (DCI) in the Well
Delivery Process
Blaise G. Nzeda and Juergen H. Schamp, Wintershall Holding GmbH
Copyright 2014, Society of Petroleum Engineers
This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 10 –13 November 2014.
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Wintershall has developed a Drilling Complexity Index (DCI), which is a tool that is used to measure the
complexity of a well. It is an early warning indicator and a measurement of how easy or difficult a specific
well can be delivered. The DCI can be used at any phase of the well delivery process; from the
pre-screening or conceptual phase through the detailed design phase to the execution phase.
Wintershall’s HQ based Best Practice unit for Well Engineering (ESW) used well data from existing
databases to compare the DCI to other complexity indexes. Furthermore, ESW analyzed the impact of the
DCI on key performance indicators (KPI) such as non-productive time (NPT), cost per meter, and meter
per day. This paper will present the work performed and the results that show a strong impact of the DCI
on all the above cited key performance indicators.
This DCI tool was initially planned to be used by drilling teams to plan wells. Following its successful
development and roll out in the drilling groups, Wintershall looked at ways to expand its use and quickly
realized that its usefulness extend beyond the drilling groups.
This paper will further describe how the DCI can be used for the following purposes:
Predict NPT of drilling projects based on DCI
Determine the time contingency for a well
Determine the cost contingency of a well
Trigger peer-assists, well examination and staffing of well projects
Support role in the project approval process
Portfolio management
The work which will be presented has accelerated the acceptance and the utilization of the DCI tool
within Wintershall, and represents a significant improvement in assessing the inherent risks and hazards
and potential consequences for exploration/appraisal/development wells.
Well Complexity
Against common belief Drilling, Completing, Testing and Stimulating a well is a non-intuitive, complex
and risk-prone process which requires the precise integration of many technical and scientific E&P
disciplines (e.g. Drilling & Completion Engineering and Operations, Geosciences, Reservoir Engineering,
Figure 1—The process of drilling & completions as a sequence of “digging” and “constructing” operations
Production Engineering, Facility Engineering, just to name a few. . .). Precise mathematical and computational engineering disciplines are on the opposite side of drilling operations, which are more interpretative and subjective. Furthermore, environmentally catastrophic and potentially deadly hazards are
always lurking. This present a continuous threat until the well is finally completed and handed over to
production operations or, as for exploration and appraisal wells, plugged and abandoned.
Therefore rigsite operations represent a complex process with many controllable, but also many
uncontrollable variables involved. John de Wardt has recently compared the drilling process with a
sequence of digging, constructing, digging, constructing, and so on. . . until the target formations are
reached. Each hole section which needs to be drilled represents a sequence of digging, while the plateau
times with formation evaluation and casing running operations represent the construction process. These
processes are repeated for each hole size with decreasing hole diameter. Upon closer look it becomes
visible that the comparison of drilling operations with the mining digging process and industrial
construction processes is limited, as both industrial processes are characterized by much more certainty
in their ingoing parameters. The digging and construction in drilling operations – especially in exploration
wells - is characterized by a much larger amount of uncertainty, as the upcoming geologic formations,
pore pressures, fracture gradients and temperatures in the borehole are only vaguely known. Overpressured or fractured loss zones, squeezing salts or swelling clays may be encountered while not in the initial
forecast. Figure 1 depicts the actual situation using a common Days vs. Depth diagram to make this point.
The construction of the casing is also framed by (1)
limited accessibility and space on the rig floor and
(2) unknown hole conditions (washouts, ledges,
etc.) in which the casing is lowered, set and cemented.
All these factors and many more add to the
complexity of the well, which also increase the
potential (or risk) of things going wrong at any time.
These risks need to be adequately captured in the
well costing process – through adequate contingency time and funds allocated to the project. Furthermore, these risks should be addressed in the well
design process with technical alternatives, risks mitigations and contingency options.
This overall existing complexity has been described in the so called drilling complexity index,
which Wintershall has studied in great detail and
described and ranked in a previous paper (Nzeda,
Schamp, & Schmitt, 2014). As the company found
many imperfections in existing complexity models,
it was decided to come up with a proprietary model.
Figure 2—Low Complexity
Figure 3—Medium Complexity
1. Green for Low Complexity well with DCI
value between 0 and 2.9 (see Figure 2)
Figure 4 —High Complexity Well
2. Yellow for Moderate or elevated Complexity well with DCI between 3.0 and 5.9 (see
Figure 3)
3. Red for High Complexity well with DCI value between 6.0 and 10.0 (see Figure 4)
The index tries to quantify the level of technical and geological complexity inherent to a well to be
drilled. The main factors are:
Type of well (e.g. exploration, appraisal, development, onshore, offshore, ERD, HTHP)
Rig specifications (e.g. rig type, water depth, rig capability, operative situation, etc.)
Well trajectory (e.g. TVD, MD, HD, inclination, azimuth, targets, etc.)
Pressures & temperatures (e.g. max. MW, overbalance, drilling margin, etc.)
Casing program (e.g. number of casings, critical setting depths, etc.)
Formation issues (e.g. stability, special activities like underreaming, etc.)
HSE considerations (e.g. pressure rating of BOP stack, location, discharges, H2S, etc.)
The calculation of the DCI is achieved via a relatively simple spreadsheet, which takes very little time
(15-30min) to be filled out. A verification and approval/endorsement of the results by the Drilling
manager is mandatory and part of the workflow. For more details on the development of Wintershall DCI,
read following SPE paper (Nzeda, Schamp, & Schmitt, 2014). Figure 5 shows the input matrix of the tool:
DCI and KPI Relationships
While the previous section has described the basic use of the DCI in the Well Delivery Process, the
following section will explore the physical meaning and dependency of the well complexity (expressed
in the DCI) in relation to common KPIs and well parameters.
Figure 5—Input Matrix of DCI tool (excerpt)
For that purpose Wintershall Drilling’s Best practice unit studied and analyzed worldwide well data
from more than 21,000 wells drilled between 2008 and 2012, which were available via the Rushmore
Reviews membership. A spreadsheet used to dissect the data had 159 data columns, so a total of more than
3.3 million data points where processed and analyzed. As it was impossible to calculate the DCI for all
these wells, a strong correlation parameter was needed for the statistical analysis. This link was found
between the number of casing strings of a well and its DCI. As published in a previous paper (Nzeda,
Schamp, & Schmitt, 2014), there is a strong correlation between number of casing strings of a well and
its DCI. Subsequently, this relationship was used for the analysis of the dataset.
The following figures illustrate how the well complexity is intrinsically linked to certain well
performance metric KPIs. Figure 6 shows the clear link between DCI and the wells NPT. While a lot of
common sense is embedded in these results, it is notable how clearly these correlations show up.
Basically, a well non productive time (NPT) value is strongly correlated to the well complexity level (DCI
range) for worldwide/offshore/onshore wells.
A similar correlation can be found with drilling performance, expressed in Days/1000m [days/3281 ft]
as shown in Figure 7:
As to be expected the well complexity also correlates with well cost, here unitized as Cost per Meter
drilled (Figure 8):
Other parts of the study even indicate a close link between well complexity (here expressed as Drilling
Difficulty Index RDI as discussed in the SPE paper (Nzeda, Schamp, & Schmitt, 2014)) and the water
depth of offshore projects, as shown in Figure 9:
All these charts demonstrate that the well complexity has a very close relation to most drilling
performance parameters. The DCI therefore has a high intrinsic value as it can be used to predict a variety
of important Drilling results. This makes it a valuable tool of the overall well planning process. Traditional
Figure 6 —DCI vs. NPT
Figure 7—DCI vs. Drilling Performance
methods of assessing Drilling “Productivity” or “Efficiency” include measures of time, distance, performance, productivity and financial parameters, and most of these numbers can be closely linked to well
complexity. Because of that the DCI itself should be a part of any benchmarking process, to obtain
Figure 8 —DCI vs. Well Cost
Figure 9 —Regional correlation between DCI and water depth
answers why some of the numbers (e.g. NPT, m/d,
$/ft) are suddenly changing from year to year. Looking at the DCI may provide a valuable answer to
these questions.
Wintershall’s Well Delivery Process
Having developed the tool itself is a necessary step,
but how to embed it in the company’s overall workflows is key to making the tool a success and
achieve the desired impact on the quality of drilling
planning, costing and staffing.
At Wintershall the company wide applied and
Figure 10 —Wintershall’s Stage Gate Process
mandatory project management process called
Stage Gate Process (SGP) is the starting point for
the application of such a tool. Managing a wide variety of projects is a complex, but necessary activity
for any company in the oil & gas business. It is a structured and step-wise approach to plan and execute
drilling projects. The process is based on the five basic E&P project stages of (see Figure 10):
1. IDENTIFY (Study the well phase)
2. SELECT (Concept selection phase)
3. DEFINE (Detailed well design phase)
4. EXECUTE (Drill & complete the well phase)
5. EVALUATE (Benchmark & Lessons Learned phase)
As a project moves from one stage to another it has to pass several major decision points, or “Gates”.
Before passing through a gate, the process has appointed experts (or Gatekeepers), who need to be
satisfied that the project is sound, both technically and commercially.
The SGP is supported by an assurance process with project reviews held between the project team and
the review team. Here the DCI has quickly become a mandatory prerequisite for all reviews as part of the
local drillteams Drilling & Completion project support package. This allows comparing projects using
their DCI values and to map company’s DCI picture. A verification and approval of the DCI through the
Project Review Team which evaluates all proposed well projects is seen as an added process improvement. A statistical overview of all operating companies (OpCo) and corporate well DCIs is already
included in the companies drilling benchmarking process.
While the SGP is a corporate tool to manage large scale exploration and CAPEX projects, a detailed
well planning, execution and evaluation workflow has been developed in parallel. It breaks down this
process into specific Drilling and Completions deliverables for the project teams. This workflow now
forms the basis for Wintershall Drilling’s proprietary Well Engineering Management System (WEMS),
which is the key tool for all Drilling Engineers to fulfill their daily job tasks. Within the defined workflows
the DCI has found its definition in an associated Drilling Standard called “Drilling Complexity Index
Determination”. Several other work steps and deliverables are affected by the DCI as will be demonstrated
later in this paper. Figure 11 and Figure 12 give an overview of selected phases, work steps and/or
deliverables and their connection and dependence on the DCI.
DCI Embedded in Well Delivery Process
Within Wintershall the implementation and acceptance of the Drilling Complexity Index are beyond the
introduction stage as the DCI is currently embedded in most planning processes. As described below, the
DCI is part of the overall drilling planning, execution and evaluation workflow.
Figure 11—Drilling Planning phase workflow with DCI component highlighted
Figure 12—Drilling Define phase with DCI component highlighted
In this phase, projects and wells are “born” through the acquisition and evaluation of exploration and/or development
acreage, via seismic, exploration or field studies. Once a geologic “lead” is identified, an exploration well is
envisioned by G&G and Reservoir Engineering disciplines. Furthermore, possible field developments options are
drafted and evaluated. Drilling Engineers start their well design process with preliminary offset well reviews and
preliminary well design with necessary data and information received from G&G. This eventually leads to an initial
base case design and the development of an initial (early) Drilling Complexity (DCI). This number will represent
the first identification of the projects complexity, which will also be used to determine the Time & Cost estimate
(via the time contingency dependent on the DCI).
➢ Develop early DCI for well complexity
➢ Determine time contingency for cost estimate
Select Phase:
The (Concept) Select phase kicks off with an accepted Statement of Requirements (SOR) from G&G, which is the basis
for technical and feasibility studies for the well. Developed well design options can be evaluated and compared with
the help of their DCIs. The chosen concept and well design will have a DCI, which again triggers NPT time
contingency levels in the time and cost estimate. Both time and cost estimate and DCI will be part of the
presentation materials in well reviews of the Stage Gate Process.
➢ DCIs for well design options
➢ Determine time contingency for cost estimate
➢ DCI for cost estimate in Stage Gate project reviews
In the Define or also called Detailed Design phase, competency requirements for the Drilling Organization need to be
developed based on the well complexity. Also detailed design reviews and Peer Reviews will be steered by the DCI
level, with increasing activities and process steps triggered by the DCI. The final and approved well AFE will again
be based on the DCI level. Documented well objectives and performance expectations will also be subject to the
DCI level.
Define drillteam competency requirement (aka Crew Resource Management)
Trigger Peer reviews and design reviews by DCI
Determine time contingency level of well AFE
Determine well objectives and performance expectations
This phase represents the Drill & Complete phase of the well. As the DCI is mainly a planning tool, only few steps are
related to the DCI level. In Wintershall the decision to perform corporate Well Monitoring (DCI 1-6.0) or perform
independent (third party) Well Monitoring (DCI ⬎6.0) is triggered by the DCI.
➢ Trigger in-house Well Monitoring via 3rd party Well Examination
The project close out phase has the main tasks of performing cost reconciliation, capturing the Lessons Learned and
develop identified Best Practices. Some may decide to calculate a post well DCI and compare it to the initial go-in
number. All of this should be documented in the End of Well Report (EOWR).
➢ Calculate a post well DCI
➢ Document KPIs, DCIs and other results in EOWR
Well Time and Cost-Estimating Process
During the well planning process, offset wells, when available, are used to estimate the duration of
specific drilling activities. These activities are categorized in productive and non-productive activities.
Non Productive Time (NPT) is the time spent on activities that DO NOT contribute to the progress of well
operations towards their objective. Net operating time is the time spent on planned activities.
Contingencies are time and cost allowances for certain events such as stuck pipes, adverse weather
conditions and mechanical failures that are unpredictable but can have a significant impact on the time and
cost to drill a well, when they occur. Unplanned events usually occur during drilling operations and do
cause NPT that may lead to projects cost and/or time overrun. Therefore, any drilling time and cost
estimate should include some contingency.
The time distribution of the new well is composed of (see Figure 13):
➢ Net operating time from offset well activities that will also be performed in the new well and
➢ Additional well activities that were not performed in offset wells (e.g. coring, logging) and
➢ Project contingency
The contingency of a well has the following two components:
Figure 13—Time Categories
➢ Non Productive Time (NPT), which includes waiting on weather (WOW), avoidable and unavoidable lost time
➢ Drilling project specific risks
Before the DCI process was developed and implemented, engineers either used their experience to set
the contingency for each project or used some values mandated by their company.
Time Contingency
Wintershall data analysis of more than 21,000 wells clearly shows that a well NPT is strongly correlated
to its DCI value (see SPE paper (Nzeda, Schamp, & Schmitt, 2014)). Therefore, the DCI of a well is
currently being used in Wintershall to determine its time contingency. A detail analysis of well data
enabled us to determine the contingency percentage for various DCI levels as per Table 1.
During drilling time and cost estimate, a project time contingency is to be determined, using the well
DCI, as per Table 1 below.
This time contingency percentage is applied to all time related cost items such as rig rate, tool rentals,
professional services, etc.
Cost Contingency
The cost contingency is determined as described below:
I. Use DCI to determine the time contingency (as per Table 1)
II. Calculate the total net time based cost by summing up the cost of all time based items (such as
rig, equipment rental, professional services, etc.)
III. Calculate the total gross time based cost by applying the time contingency to the net total time
based cost.
Total Gross Time Based Cost ⫽ Total Net Time Based Cost x (1 ⫹ Time Contingency [%])
IV. The total net well cost is calculated as sum of tangible costs and total net time based cost
Total Net Well Cost ⫽ Total Net Time Based Cost ⫹ All Tangible Costs
V. The total gross well cost is calculated as sum of tangible cost ⫹ total gross time based cost
Total Gross Well Cost ⫽ Total Gross Time Based Cost ⫹ All Tangible Costs
VI. The cost contingency is total gross well cost divided by total net well cost.
Cost Contingency [%] ⫽ (Total Gross Well Cost / Total Net Well Cost) –1
Total Gross Well Cost ⫽ Total Net Well Cost (1 ⫹ Cost Contingency [%])
The calculated cost contingency is lower than the above time contingency because of the inclusion of
tangibles costs such as OCTG, well head, etc. E.g. A time contingency of 35% may result in a cost
contingency of 22% depending on tangible costs.
Table 1—Time Contingencies
These contingencies, time and cost, are used to estimate drilling project duration and cost.
DCI as Trigger for Project Assurance Processes
The DCI is also used as a trigger for the following processes:
Peer Assists
Well Monitoring
Well Examination
Peer Assist can be requested by any stakeholders to address issues that arise during the well planning.
However for wells with medium to high DCI, there are more stringent requirements.
For medium DCI wells, a Peer Assist meeting should be requested to review and mitigate activities with
specific concerns (red-level activities).
For high DCI wells, a Peer Assist meeting must be organized to review well planning and design. The
objective of the meeting is the mitigation of activities with high complexity or with specific concerns.
Wintershall has a corporate Drilling Support team that conducts well monitoring for all its worldwide
drilling operations. This team of experienced drilling experts independently assesses drilling operations
and advises the rig teams.
For wells with high DCI (DCI ⬎ 6), Wintershall hires a Well Examination company to provide an
independent assessment that the wells are designed, constructed, operated, suspended and abandoned in
accordance with oil and gas industry standards.
It is important to note that in some countries (e.g. United Kingdom), there is a regulation making Well
Examination mandatory for all drilling operations within its border. Wintershall conducts Well Examination on all wells, independently of their DCI values, in the countries where it is mandatory to do so.
Corporate Approval Process
Wintershall corporate project approval process requires a team of company experts (Review Team) to
independently review the work done by the project team, if necessary, suggest improvements and provide
approval recommendation to senior or executive management. The documentation package, submitted by
the project team to the Review Team, must include a signed DCI sheet. Therefore, the DCI has become
a valuable decision element in the corporate approval of a well and/or field development.
Portfolio Management
The entire company project portfolio can be presented in a DCI mapping showing projects together with
their mean DCI value (see Figure 14). The US dollar value or reserve volume of each project can be used
Figure 14 —DCI Mapping of Project Portfolio
to determine the size of its box on the mapping. Below are various ways to use the DCI and DCI mapping
in portfolio management:
It can be used to determine the DCI distribution within the company or in each country or each
region that Wintershall operates in.
● This elevates on a simple map the drilling complexity and associated costs for all projects in the
● It can be utilized by business development or exploration teams to see where a project of interest
fits in the company DCI mapping.
● It can be utilized to determine the DCI level (low, medium or high) of project to pursue/acquire
in business development.
A well complexity index distribution as shown in Figure 15 would also be very useful for the
understanding of the overall portfolio risk as shown below:
KPI and Benchmarking
DCI is also used in the benchmarking process. The drilling performance of a rig or operating company
is displayed against the DCI of the wells drilled. The DCI is a way to normalize drilling performance. How
do we compare the performance of a rig or team drilling low DCI wells against performance a rig or team
drilling high DCI wells? Does meeting or missing well duration and cost targets mean the same thing for
both rigs and/or teams with low and/or high DCI?
The detailed analysis of well data has proven that NPT increases with increasing DCI. As Figure 16
shows, over the last 4 years the mean DCI values of wells drilled by Wintershall have gone up moderately
from 3.1 to 5.0, while NPT has jumped from a low 9.8% to 23%. This clearly identifies that other factors
besides the DCI itself are involved. As such the tool can be used to identify sources of trouble.
Another potentially useful display is the weekly management report, where wells could be displayed
in DCI matching colors (green ⫽ low complexity, yellow ⫽ medium complexity, red ⫽ high complexity)
in a master drilling schedule to focus on the critical wells (see Figure 17).
Figure 15—DCI distribution for Wintershall Wells
Figure 16 —NPT increasing with DCI
Crew Resource Management
Crew Resource Management (CMR) represents an already existing science which is being applied by
several accident critical industries as varied as the aviation industry or the military. The application of
CRM in the oil and gas industry is relatively new, and promoted by a few leading edge E&P companies.
A detailed training curriculum is currently developed through OGP’s Wells Expert Committee (WEC) and
may become part of future IADC and IWCF Well Control training. While it may be beyond the means
of current data analysis capabilities to show a link between CRM and NPT and/or Well Complexity, the
well complexity classification can also be applied to indicate increased staffing and experience needs for
drilling engineering and operation teams. Such “Competency Management”, which should encompass a
detailed mapping of the rig & office crews’ experience, may be made mandatory by regulators as also
Figure 17—Example of a Master Drilling Schedule showing complexity of wells
Figure 18 —Basic Competency Evaluation Tool (for DCI 1.0-6.0)
expressed in new regulations like the European Offshore Directive, which will become effective in
summer 2015.
Competency Assurance
Competency Assurance is another HR process closely linked to the CRM issue and also mandatory
requirement of many Governmental regulators (e.g. UK DECC, Norwegian NORSOK,). As crew
competency is more critical on complex wells, Wintershall has decided to link the Competency Assurance
process to the DCI level. In all low and medium complexity wells (DCI 1.0-6.0) competency is assured
via a relatively simple spreadsheet which is part of the overall yearly HR process. If the well is a complex
well (DCI⬎6.0) another much more detailed spreadsheet has to be filled out by all critical field and office
personnel. As such the available crew competency requirements for complex wells are captured in much
greater detail and can be analyzed and linked to incidents. Figure 18 depicts the Wintershall proprietary
HR competency tool.
QA/QC Efforts
Another potential use of the tool is in the field of QA/QC. While a poorly executed QC job can wreck any
well – even with a low complexity – it appears to be logical that complex wells require more complex
equipment, which again require increased QA/QC efforts to avoid train wrecks. Therefore Wintershall is
currently investigating the relationship between the DCI, the resulting NPT and potential root causes
through equipment/rig failures. Overall the tool could serve a further use as a QA/QC effort indicator.
The paper discusses 1st the development of a well complexity index in Wintershall, 2nd how the DCI
correlates with well drilling performance and cost metrics, and 3rd how this tool is embedded in the overall
well planning, execution and evaluation workflows. It demonstrates how the drilling complexity index
correlates with various drilling KPIs and metrics and why and how the index can be used for well
planning, staffing, and well costing purposes. While the overall importance of the DCI is clearly
demonstrated via a thorough data analysis and a comparison to similar other efforts to describe well
complexity, the following conclusions can be drawn:
Drilling operations comprise a complex process of repeating sequences of “digging” and “construction” operations. Both process steps have to be carried out under sometimes adverse and
uncertain physical circumstances, which add significant complexity to the process and are
commonly expressed in drilling hazards and risks.
Wintershall has captured the subsurface complexity of this process with a Drilling Complexity
Index which summarizes all well inherent risks in a unitized 1 to 10 scale.
The Drilling Complexity Index (DCI) is calculated via a simple spreadsheet based tool. It
calculates a well complexity based on drilling technical, geological, HSE, and rig related parameters.
The DCI is a valuable tool for the well planning process of Drilling Engineers. It can be used for
an early risk & hazards evaluation of the well being planned. As such, it is used for the comparison
of different well concepts during the concept selection phase.
The DCI correlates strongly with other key well performance parameters like NPT, meters/day and
also cost metrics, and therefore can be used as a tool to identify required time contingencies in the
well costing process.
The overall portfolio DCI can be tracked over time and the tool is being used by Wintershall to
trigger certain process steps in the well planning process (e.g. requirement for peer assist or
reviews, or well monitoring/examination options, drillteam staffing).
HR related processes like Competency Assurance or Crew Resource Management can be steered
with the help of the DCI tool providing guidance on required personnel resources and competency
The DCI can be used in corporate and affiliate benchmarking exercises to indicate the well mix
of any given time frame or country/operating company. Critical wells can be shown on the master
drilling schedule and thus highlighting critical operations requiring more attention.
Wintershall uses the DCI tool widely throughout its benchmarking exercises and in the corporate
project review process. The tool has been widely accepted and has proven its use in a very short
time period. More uses are discovered while the tool is being applied and more research work is
being conducted.
Nzeda, B., Schamp, J., & Schmitt, T. (2014). Development of Well Complexity Index to Improve Risk
& Cost Assessments of Oil and Gas Wells. Society of Petroleum Engineers.
Rushmore, P. (2011). Society of Petroleum Engineers. Anatomy of the “Best In Class” Well: How
Operators Have Organised the Benchmarking of their Well Construction and Abandonment Performance.
Kile, Hogne: The Statoil Well Complexity Index - Rushmore Reviews November 8, 2011