SPE-120195-STU (Student 3)
Redeveloping a Permian Basin Waterflood
Eric M Looney, The University of Texas at Austin
This paper was prepared for presentation at the 2008 SPE International Student Paper Contest at the SPE Annual Technical Conference and Exhibition held in Denver, Colorado, USA, 21–24
September 2008.
This paper was selected for presentation by merit of placement in a regional student paper contest held in the program year preceding the International Student Paper Contest. Contents of the
paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any
position of the Society of Petroleum Engineers, its officers, or members.
Abstract
There are thousands of small oil fields across west Texas past their prime production periods that have produced millions of
barrels of oil, but produce less than a hundred barrels today. These fields have potential but had never been the best
investment opportunity and have been continually passed over for more exciting projects. A study over a similar field will be
presented in this paper; a project undertaken by undergraduate interns on a field that was low on the team’s priority list but
still had potential to add reserves.
The lease being redeveloped is primarily an oil lease that has produced over eleven million barrels of oil equivalent over the
past forty-five years, but has not seen any development for over a decade. The principal objectives were to update the
geological maps and correlations, determine the bypassed hydrocarbon potential, and create a plan to accelerate reserve
recovery.
Introduction
As the price of oil continues to rise, the risk to reward ratio for redeveloping old oil fields keeps improving. Increased
attention is being paid to fifty year-old fields in order to maximize profits with prices at all time highs. Because old fields are
studied and redeveloped instead of simply maintained, the engineer’s work load continues to swell. Important, value adding
projects are increasingly being assigned to undergraduate engineering interns. An example of such a project will be given in
this paper.
The field was discovered in the mid-1960s, and is geographically located in the Permian Basin region of Texas, west of
Midland. A majority of the field was originally developed with a shared water injection project between the two primary
operators. A total of 30.1 MMBOE has been produced.
The specific lease studied accounted for over a third of field production. It is one of only a couple large, productive leases in
the field. Operators have been interested in doing work on the lease since the early 1990s as evidenced by the independent
field studies commissioned, the most recent being in the early 2000s. However, no wells were drilled and no significant work
other than routine maintenance was done in the last decade.
During the summer of 2007 a geology intern and I were given the responsibility of studying this lease and creating a plan for
future development.
Project Objectives
The lease history was not initially clear; therefore, it was necessary to analyze field performance and review past methods of
maximizing recovery. This was time intensive and involved data mining to make certain that the lease production and
workover history was accurate in the database. Geology re-correlated all logs to update flow units in the field. The initial
hypothesis was that the inherited map’s flow units were not lined up properly based on the inability to reconcile water
injection and production data. The logs were reviewed so flow units and mapping could be updated and volumetrics
recalculated. The key to the project was identifying bypassed reserves and how to produce them. It was determined that there
is an economically feasible amount of hydrocarbons remaining; therefore, a development plan was created.
The Lease
The primary formation in the reservoir is Strawn Detrital. It is important to note that the Strawn Detrital is a sandstone
formation because, from speaking with engineers and geologists experienced in the area, the Strawn is typically a carbonate
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formation. The only fluid sample was taken in the initial well before production commenced, at the discovery bottom hole
pressure of 3000 psia. The fluid’s bubble point pressure is 1950 psia; the reservoir was undersaturated and no gas cap present
at initial conditions. Two core samples were taken. The primary drive mechanism is solution gas expansion aided by gravity
segregation.
Over two thousand acres were studied with well spacing between eighty and 160 acres, which is large for a west Texas oil
lease, especially of this age. There are currently less than ten active wells on the lease including temporarily abandoned and
injection wells. The remaining wells have been plugged and abandoned; the majority of them failed due to mechanical
problems. Infill drilling has been successful in several cases, and will be a primary strategy for accelerating reserve recovery
in the development plan.
The bottom hole pressure decline in the wells was a concern from the beginning. Pressure surveys and build-ups were run
regularly until the wells started on rod pump after a few years; there are no definitive bottom hole pressure test results after
1971. A series of echometer pressure build-ups were done in the late 1980s but it is not certain that the wells were out of the
wellbore storage period after over 100 hours of shut-in time. During the summer of 2007 the wells were shut in for over a
week due to an issue at the gas plant which allowed the operators to shoot static fluid levels but the results were inconsistent.
As a result of the rapidly declining pressure, the initial operator entered a joint pressure maintenance project with an offset
operator. No injection wells have been drilled on the lease to date, but some wells were converted from production to
injection in a combination line drive and peripheral flood pattern. Because the reservoir was viewed as one thick layer across
the lease, this seemed like a logical initial pattern for a waterflood. The new mapping would show that few of the
injector/producer pairs had connecting perforations. This is supported by a lack of water production in some production wells
offsetting an injector; the lease has only produced about a third of the amount of water injected. Additionally, it is not
believed at this time that there is an aquifer supporting the reservoir due to low water production, low pressures, and lack of
reservoir continuity.
Reservoir Geology
The large well spacing on the lease has made it difficult to accurately characterize the geology. The depositional environment
was a meandering migrating fluvial system with multiple channel sands that do not appear to be connected from production
and injection data. As a result of the depositional environment, the pay sands are compartmentalized and it is difficult to
determine the boundaries of the reservoir pockets unless a well is drilled. Further, it is difficult to have a successful
waterflood in this environment when the flood is approached on a large scale instead of an individual well basis.
The team viewed the remaining core taken on the lease at Core Lab’s facility in Midland, Texas. Prior to viewing the core it
was not completely clear whether the main reservoir rock was a carbonate or sandstone; however after viewing the core it
was obvious that it is a clastic environment. The amount of core remaining was limited; Figure 1 below is only about ten feet,
but the shale, sand, shale sequence is clear.
SPE-120195-STU
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Figure 1. Strawn Detrital Core
After determining that the primary reservoir rock is a sandstone, a new set of Pickett plots were created to more accurately
calculate the irreducible water saturation. From the Pickett plot the irreducible water saturation was determined to be about
18% which is much less than the 35% that had been assumed previously.
For the new correlations seven individual sand packages were identified across the lease. The gamma ray log signatures in
each sand layer were distinctive enough to make the differentiation between layers. The type log in Figure 2 shows the
alternating sand/shale sequence on the gamma ray track.
Figure 2. Strawn Detrital Type Log
After correlating sand layers, cross sections were created to show the zones that are not connected in offsetting wells. Further,
the perforations on some of the injector/producer pairs did not connect and were not providing pressure support. The cross
section in Figure 3 is an example of the way the sand layers thicken and thin across the channel.
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Figure 3. Strawn Detrital Cross Section
It is possible that some shale layers between pay zones pinch out between wells or allow crossflow. The lack of an
impermeable layer would help explain the water that some of the wells produced and the isolated appearances of pressure
support in producing wells with offset injectors that do not correlate; however this cannot be determined without an
additional well or wells.
Volumetrics
Changing the rock type from a carbonate to sandstone had an effect on the volumetric calculations. From the Pickett plots a
new irreducible water saturation and porosity cutoff were determined and applied to net pay. Further, the formation volume
factor of oil was recalculated and updated to reflect data in the PVT report. A summary of the volumetric parameters in the
previous and current calculations is shown in Table 1 below.
Table 1. Volumetric Calculation Comparison
Volumetrics Comparison
Previous
Current
Original Oil in Place
28.3 MMSTB
35.4 MMSTB
Porosity Cut-off
8%
5%
Water Saturation
35%
18%
Formation Volume Factor
1.25
1.33
Oil Recovery
34.2%
27.4%
Gas Recovery
57.8%
47.9%
Production appears to be confined to the study area and unaffected by outside wells. The current recovery factor is 27% of
the original oil in place, which indicates that the waterflood has seen moderate success in some wells. The recovery is still
low enough for a waterflood to conclude the presence of bypassed reserves.
Reservoir Discussion
From the geologic aspect, it is clear that the reservoir is composed of compartmentalized pockets that are not all connected.
With large spacing and lack of geologic control, it is difficult to determine the exact location of the channel sands and
assumptions were required for the maps. To add accuracy, offsetting production was analyzed in wells with connecting
perforations to find evidence of communication. When perforations were aligned in offsetting wells the water cut, oil rate,
gas rate, and GOR were compared to determine connectivity. It is logical, but not entirely conclusive, that an updip well
should have a higher GOR, smaller oil rate and smaller water cut than a downdip well in the same zone. When this was not
the case, the zone was assumed to be discontinuous and the maps adjusted accordingly.
SPE-120195-STU
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The updated cross sections indicated that the bulk of the water injection had not been successful. There was potential for
improving the waterflood because there were a few instances that showed a positive production response from aligned
perforations in injector/producer pairs. Figure 4 below shows a well that responded to water injection but watered out quickly
after the water broke through. As an interesting note, the well was shut in at about ten barrels of oil per day, which would still
be economic at today’s prices.
Figure 4. Waterflood Response
The most important challenge in the field is maintaining reservoir pressure. The early wells showed that the natural pressure
would deplete quickly, which is why waterflooding was tried early. From the recent static fluid levels, it was clear that there
are pockets of reservoir with little pressure remaining – one well had a fluid level that corresponded to less than 100 psia.
Some of the fluid level pressure data was inconsistent though, as another well had a fluid level corresponding to a bottom
hole pressure several hundred pounds higher than discovery pressure, and a second fluid level a few months later that
indicated only a few hundred pounds in the same well. More static levels would be needed to increase accuracy, but the
current data at least provides some insight into the reservoir. Due to the inconsistent pressure history, reservoir
compartmentalization, and unknown channel connectivity, a reliable material balance result was not produced.
From production history there is also evidence of secondary gas caps forming. As pressure declines and the producing GOR
rises above the solution rate, the wells begin producing free gas. As additional gas cap evidence, several updip wells have
gassed out. Figure 5 below is of a well that is high on the structure and produced at the solution GOR (about 750 scf/stb) for
the first ten years of production after which it rose considerably and began producing free gas from the reservoir.
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SPE-120195-STU
Figure 5. Gas Cap Formation
Development Plan
The strategy behind the development plan centered on a new set of criteria for picking a drilling location; a new well must
have evidence of:
A significant amount of pay
Multiple reservoir layers
No gas cap
Potential strategically placed water injection
From the 86% success rate on the lease, the dry hole risk is not as great as the risk of drilling into a pressure depleted zone.
Due to the relatively low total production rates from the lease and high well costs there are not going to be multiple chances
to drill a successful well. The requirement of significant amounts of pay across multiple layers provides more opportunities
for successfully finding a quality zone. To avoid depleting reservoir pressure by producing a remaining gas cap, all wells are
to be drilled as far down dip from known gas caps as possible. It is also desired to a drill a large enough hole that a sidetrack
could be drilled in the event that the target is not present or if a lateral option was desired in the future. Increased costs from a
larger wellbore could be prohibitive and would need to be evaluated on a case-by-case basis. Lastly, as wells are drilled and
geologic control is added to the mapping, strategic waterflooding should be implemented. Alternatively, if an injector
location (or convertible producer) does not appear connected in the same zone then the economics would not be justifiable.
The complete development plan includes a total of nine development wells, all initially drilled as producers, with plans to
convert at least three of them to injection wells if updated mapping indicates that the new wells are connected. It is an
aggressive strategy for an aging reservoir, which is why the plan should be implemented in stages with the lower risk, high
impact wells drilled first. The lower risk wells have known oil nearby, lower chance of pressure depletion, greater potential
for injection support, and smaller spacing. The riskier wells are generally the first infill in an area with less data and more
unknowns in defining reserves, pressure, and potential injection support. Two recompletion candidates were identified, one
currently producing and the other temporarily abandoned. Both wells have a prospective zone up hole from the primary
producing zone that has not been perforated in a nearby well.
Current State
As of the writing of this paper, two of the recommended wells have been drilled. The first well encountered hole problems
near the pay zone which made it impossible to get a complete set of open-hole logs. This well is still in the process of being
tested and evaluated but does have potential to be an economic well. The second well has been tested and appears to be
successful at this point.
Conclusion
It is still too early in the redevelopment process to consider this project an economic success. The first wells are going to be
evaluated closely and hopefully the team continuing to work the field can build on the new data and continue to find
SPE-120195-STU
bypassed oil. The multi-disciplinary approach taken produced a more complete understanding of the subsurface and better
developed plan with greater chance of success and should be used as a model for utilizing internships to create value for a
company.
Acknowledgements
The author would like to give special acknowledge to Dr. Paul Bommer and all professors at The University of Texas at
Austin for their advice and encouragement in the development of the paper and presentation for this competition.
References
Craig Jr., Forrest F.1971. The Reservoir Engineering Aspects of Waterflooding. Monograph Series, SPE, Dallas, TX.
Dake, L.P. 2001. The Practice of Reservoir Engineering (Revised Edition). Elsevier Science, Amsterdam, The Netherlands.
McCain Jr., William D. 1990. The Properties of Petroleum Fluids, Second Edition. PennWell Books, Tulsa, OK.
Walsh, Mark P. and Lake, Larry W. 2003. A Generalized Approach to Primary Hydrocarbon Recovery. Elsevier, New York
City, NY.
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