SPE 114171

Unconventional Resource Play Evaluation: A Look at the Bakken Shale Play of North Dakota Stuart A Cox, David M Cook, Ken Dunek, Reagan Daniels, Connie Jump, Marathon Oil Company; and Bob Barree, Barree & Assoc.

Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 SPE Unconventional Reservoirs Conference held in Keystone, Colorado, U.S.A., 10–12 February 2008. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract Unconventional resource plays can provide a long-term supply of oil and gas to help supplement the North American energy demands. However, obtaining a good economic return from these developments can be challenging. A successful entry into an unconventional play requires careful pre-entry analysis in order to develop meaningful production profiles and set realistic expectations. Wells completed in unconventional plays typically exhibit limited drainage areas and produce a majority of recoverable reserves at low rates. Due to the limited flow capacity of these reservoirs typical development strategies include some form of horizontal completion. When considering a potential entry into a “new” resource play there are a number of important questions that must be answered such as “What is an appropriate range of initial production rates and reserves for the development?” or “What is the most cost effective completion method?” and “How will post drill completion efficiency be determined?”. This paper will present one operator’s approach to answer these questions for its entry into the Bakken Shale development of North Dakota. The paper focuses on the effective use of existing public information to frame expectations for the development. It will also present the completion design considerations and initial implementation results from the development.

Introduction The initial production from the Bakken Formation of North Dakota began in 1950’s as a back up zone should other primary targets fail to be productive. The play experienced two further development periods. The first development phase was comprised of vertical completions. According to public records a total of 145 vertical wells were drilled in North Dakota and completed from 1953 to 1991. These wells were completed in the entire Bakken interval and have a cumulative production of approximately 11 MMSTB. On average the historical vertical wells had an initial production rate of 28 BOPD and are expected to recover 85 MBOE per well.

The second phase of development began in 1987. During this phase 225 horizontal wells were drilled targeting the upper Bakken Shale interval. On average the upper shale horizontal wells had an initial production of 86 BOPD and a projected ultimate recovery of 145 MBOE. Figures 1 and 2 show the initial production and the historic EUR distributions for North Dakota Bakken wells. The economic results of the first two stages of development were marginal. However the successful results demonstrated by the Middle Bakken development of the Elm Coulee field in Montana have prompted a further round of development in North Dakota. A careful review of the historical results of the prior development work can provide valuable insight into the potential performance of this new Bakken development. One should not assume that the success demonstrated in Montana will be automatically duplicated in North Dakota.

Geological Overview The Bakken reservoir of North Dakota is comprised of an upper shale member underlain by sandstone/siltstone members bounded by the lower shale member. Figure 3 is a type log of the geologic section1. The current development is focused on the Middle Bakken interval. Typically this interval is approximately 30 feet thick. Table 1 summarizes the average reservoir properties of the Middle Bakken interval. Much has been published on the Elm Coulee field in the Richland County, Montana Bakken play, which is similar in some ways to the more quartzose western North Dakota portion of the play. The main Middle Bakken lithofacies are present to some extent throughout the basin, with notable variations. In general, the Middle Bakken is a marine sandstone or siltstone with considerable percentages of carbonate grains and cements. The Elm Coulee field is developed in a very dolomitic facies where porosity and permeability are relatively high due to partial dissolution of interlocking replacive dolomite rhombs. The North Dakota productive Middle Bakken exhibits comparable depositional

2 SPE 114171

characteristics but has more of a clastic framework of quartz, feldspar, and reworked fossiliferous carbonate grains and smaller amounts of dolomite. Primary porosity with reduced amounts of secondary porosity is the main driver in the reservoir system in North Dakota. Figure 4 shows part of the Middle Bakken interval from a pilot hole core in Dunn County, North Dakota. Sedimentary structures, burrows, lithology, and lateral facies association helped point to a lower shoreface or offshore type of depositional environment.

Pre-Development Analysis The goal of the pre-development analysis phase is to determine the productive potential of the resource play. This can be accomplished by detailed analysis of the available information for the play. It is critical to have performance from vertical completions in order to predict horizontal performance. If an offsetting development is in progress the results of the existing development should be critically reviewed to determine if it is an appropriate analogy. In our case we will compare the results of the Elm Coulee development in Montana to the proposed development in North Dakota. The following is a workflow for the evaluation of the productive potential of a resource play with existing vertical completions.

1. Evaluate historic production trends of vertical and horizontal completions.

2. Estimate the effective drainage volume for both

completions. 3. Determine the effective fracture half length for the

vertical completions. 4. Estimate the formation flow capacity. 5. Compare and contrast existing offset development

with the proposed development. 6. Develop a production profile for the proposed

Middle Bakken development.

Historic Production Trends For the prospective development there are a large number of vertical and horizontal completions representing a significant geographical area of North Dakota. These data are available through public sources1 and were used to construct individual decline curves for each well. Bakken well production is shown in Figure 5 for various completion vintages. The production curves have been averaged to show the improvements in completion efficiency made over time. It can be seen that the recent phase of production represents a step change in the development

results. A second peak related to refracture stimulation can also be seen in the most recent Bakken production. This is standard practice in the Elm Coulee field of Montana2. The spacing and length of the Bakken horizontals making up the 2000-2006 curve are varied, ranging from short 3,000-4,500 ft horizontals to 21,000 ft multilaterals. On average the historic vertical completions had an initial production rate of 28 BOPD and an average projected ultimate recovery of 85 MBOE. The historic upper shale horizontal completions had an average rate of 86 BOPD and a projected ultimate recovery of 145 MSTBO. A typical production profile for both completion types is presented in Figure 6. The horizontal play results are those of the upper shale development phase.

Drainage Radius The historical production data was used to estimate the effective drainage volume and reservoir flow capacity of the Bakken reservoir associated with each completion. In order to do this the long term production for the well is analyzed as a drawdown test. This technique is commonly referred to as ‘production analysis’. The analytical method is essentially a type curve matching technique that combines rate time and pressure into the analysis to provide an estimate of a well’s flow capacity, completion efficiency and effective drainage volume. The technique used to estimate the well’s effective drainage volume was originally presented by Agarwal and Gardner3 in 1999 and is referred to as the Rate-Cumulative production decline-type curve. For this method Agarwal-Gardner showed that a plot of the reciprocal of dimensionless wellbore pressure, 1/PwD, versus dimensionless cumulative production, QDA, would have an anchor point of 1/2π during boundary dominated flow.

( )wfit

oDA pphAc

QBQ

−Φ=

8936.0 ……………….…………. (1)

( )

( ) oo

wfiwD Btq

ppkhp

μ2.141−

= ……………………………. (2)

In order to perform the analysis, historical rate and pressure data must be available. In our case we obtained the historical production data from the IHS Inc.4 database. Unfortunately, these data are only available on a monthly basis and flowing pressures are not typically included in the database.

Production Analysis Methodology In order to perform the analysis the information for each producing Bakken completion in North Dakota was treated in the following manner. First, the monthly reported volume was divided by the reported days on for the month to obtain an average daily production rate for each month of production. Shut-in periods were compressed to form a single production profile for each well. The next step was to estimate the initial reservoir pressure and the producing bottomhole pressure for

SPE 114171 3

each well. For consistency every well was assumed to have an initial reservoir pressure of 7,000 psi and be producing at a constant bottomhole pressure of 500 psi. The constant bottomhole pressure assumption was based on the presumption that most of the wells were placed on pump shortly after completion and that the producing pressure would remain relatively constant over the life of the well. The resulting effective drainage volumes for the vertical producers were then converted to effective drainage areas based on a constant set of average reservoir parameters that are summarized in Table 1. The effective drainage volumes for each completion are presented graphically in Figure 7. On average the vertical and horizontal wells were found to be draining from approximately 1.0 MMSTB STOIIP.

Historic Productivity and Drainage The initial production rates from the Upper Bakken horizontal completions were approximately three times higher than the vertical well completions, but their ultimate recoveries were less than twice that of the vertical wells. The results of the production analysis indicate that the Upper Bakken horizontal play did not result in an increased effective drainage area for the well when compared to the vertical completion. However, the initial production rate of the horizontal completions was three times higher than that of the vertical completion. A critical review of the production analysis results indicates that the flow capacity of the vertical completions on average was twice that of the horizontal completions. The reduced flow capacity of the horizontal completions limits the wells’ effective drainage area. Figure 8 compares the flow capacity of the vertical and horizontal completions. It should be noted that the historic horizontal completions targeted the Upper Bakken Shale while the vertical completions were typically completed across the entire Bakken interval. An estimate of the recovery factor for the Bakken completions can be made by dividing the projected ultimate recovery by the effective drainage area. The ultimate recovery is determined by decline curve analysis while the effective drainage volume is obtained from production analysis. The average recovery factor was found to be 10%. This information can be used to estimate the effective drainage area and ultimate recovery of the proposed horizontal development.

Projected Well Performance The information obtained from the review of the historical completions can be used to estimate the effective drainage area and initial production performance of the proposed Middle Bakken horizontal development. Joshi5, in his book “Horizontal Well Technology”, presents two methods of incorporating vertical well performance into the estimate of horizontal well performance. For the first method Joshi states that “a horizontal well can be looked upon as a number of vertical wells drilled next to each other and completed in a limited pay zone thickness.” In this case the drainage shape would be rectangular down the horizontal and circular on both ends. For this case the width of the drainage area along the lateral would be twice the effective radius of the vertical completion and the end would form a semi circle with a radius

equal to that of the vertical well’s drainage area. The second method assumes the drainage shape is elliptical with each end of the well being the foci of the drainage ellipse. Based on our analysis the mean drainage area of the vertical completions was 92 acres which results in a drainage radius of 1129 ft. The resulting drainage area for a 2500 ft horizontal well would be 221 acres for method 1 and 193 acres for method 2. As both methods result in a similar answer, the average of the two methods was used for this analysis. Once the effective drainage area is known, a volumetrically derived ultimate recovery can be calculated based on the average Bakken reservoir parameters and the recovery factor determined from production analysis. The projected ultimate recovery is presented graphically for horizontal well lengths of 2500, 4500 and 9000 feet in Figure 9. The next step in our analysis was to estimate an initial production rate for the horizontal completions. The initial productivity of horizontal wells can be determined using the following equation:

……………..…(3)

Where

vh

kk=β ...............…………………………….(4)

...............……..……….(5)

Equation 3 was used to estimate the initial production for the horizontal development. The results obtained from the production analysis were used to define the range of effective horizontal permeabilities. This distribution ranges from 0.0003 to 3.36 md with an average of 0.25 md. The distribution of horizontal permeability is presented in Figure 10. For this case we assumed that the vertical permeability of the matrix was two orders of magnitude lower than the horizontal permeability and that the wells would have a 3000 psi drawdown. Based on these assumptions, the P50 rate for a horizontal completion in the Middle Bakken is expected to range from 130 to 425 BOPD depending on contributing length. The full distribution of rate potential based on this analysis is show in Figure 11. Production Profile It is common to use decline curve analysis to generate long term production profiles. However, resource plays are not well suited for this type of analytical tool. Due to the low effective permeability of the reservoir, a large portion of the wells’ productive life is spent in transient flow. Therefore it is recommended that simulation studies be performed on the

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4 SPE 114171

potential development in order to establish the long term profiles required for economic evaluations. Reservoir parameters and effective drainage areas obtained from the historical completions can provide a basis for the reservoir parameters required for the simulation work. A reservoir simulation model was constructed using the range of characteristics obtained from the predevelopment analysis. The aim of this work was to generate a production profile based on the range of properties present in the Bakken reservoir. The value of the simulation work is to ensure that the resulting production profile honors the physics involved in production. The models were constructed so as to match the estimated drainage areas, and the initial production rates obtained for the analytical results. The model was gridded so as to increase the cell sizes logarithmically away from the wellbore, which can be seen in Figure 12. The resultant profiles generated can be seen in Figure 13 and are summarized in Table 2.

Completion Design The Bakken Shale development has a very low flow capacity and will require effective stimulation in order to achieve an economic rate from the producing well. The historic completion attempts in the North Dakota Bakken consisted of fracture stimulated vertical completions and unstimulated horizontal completion. Both techniques have proven to be largely uneconomic. However, the Elm Coulee Bakken development has shown that economic completions are possible in this low permeability oil development. A number of completion strategies are currently used by the various operators in the field. The only common thread is the fact that the recent wells are horizontal and fracture stimulated. The evaluation of horizontal completion efficiency is paramount to picking the most effective completion technique. This has proven to be a difficult task based solely on public information. Care should be taken to determine the cause and effect of performance differences when evaluating various completion techniques. It is clear that the performance of a well is directly proportional to the contributing length of the lateral, which is in turn directly related to the effectiveness of the fracture stimulation. One potential way of evaluating the effectiveness of the completion was described in SPE 906976. Our primary goal for the initial completion design was to cost effectively maximize the contributing length of the lateral. Based on the results of the subsurface analysis it was determined that a 9,000 ft lateral would deliver better economic result if the long lateral could be effectively stimulated. Effectively stimulating such a long lateral section has proven challenging in both the Elm Coulee and North Dakota developments. However, one operator in the Elm Coulee field has demonstrated superior results and therefore our initial completion incorporates some of their completion practices. The completion design initially adopted for the 8000-9000’ laterals uses an un-cemented liner in an open-hole horizontal. The un-cemented liner was selected to allow for induced or

“dynamic” diversion of the frac so that multiple initiation points could be achieved. The absence of cement in the hole also minimizes damage to any possible existing natural fractures, shear fractures induced during drilling, or secondary porosity that may enhance communication with the reservoir. The completion consists of a (typically) 4.5” liner in a 6-1/8” to 6-3/4” drilled hole. A short liner sub, with 5-6 pre-drilled holes, was run every 4-5 joints in the completion interval. A liner-top packer or seal assembly was normally run and the fracs were pumped down casing and bull-headed into the liner. The liner and open annulus form a concentric alternate path geometry which allows fluid and proppant to be delivered along the lateral, even in the event of a partial screenout and annular pack-off at various points along the lateral. The relative sizes of the liner and annulus are considered important to the successful application of the diversion process. As explained in SPE 90697, the hydraulic radius of the liner and annulus should be configured so that with approximately 70-80% of the total injection rate in the liner, and the remainder in the annulus, the liner and annular pressure gradients will be in equilibrium. This assures that open perforations (or pre-drilled holes) near the heel of the well will not act as “thief zones” to cause an early screenout. Diversion is achieved by inducing a partial screenout of a propagating fracture at some random point along the lateral. The screenout can be induced by several means including reducing of pad, pumping high slurry concentrations, cutting gel loading, dropping rate, pumping large sand, or various combinations of these methods. Once a partial screenout is achieved, an annular pack forms outside the liner which effectively creates an obstruction which is nearly as effective as an external casing packer. The remaining open annulus is subjected to the increased treating pressure resulting from the partial screenout, and a new fracture initiates and is propagated until it can be screened-out. In some cases perf balls are also used to reduce fluid flow into an open fracture that does not screen-out by one of the previous methods. Figure 14 shows an example of the diversion achieved in an 8000’ lateral using a combination of these methods. In this job the treating pressure increases by nearly 2000 psi during the single lateral frac. The early stages show increased pressure after each diversion stage, but no obvious additional breakdowns. Later in the job the pressure becomes more erratic, pressure spikes are higher, and several sawtooth breaks occur that may correspond to additional fracture initiations. Based on multi-isotope tracer logs in many horizontals in the Elm Coulee area, this degree of pressure rise is needed to ensure stimulation of a large part of the drilled lateral length in that field. The success of this type of completion can be verified by comparison of cumulative production curves normalized to the drilled lateral length. Figure 15 compares normalized production curves for wells completed with uncemented liners and dynamic diversion to open-hole completions without liners, cemented liners with limited-entry fracs, and multi-laterals7. At the time of the latest comparison the uncemented

SPE 114171 5

liner wells with diversion out-performed any other completion type by more than 3-fold. Based on this information, and assuming that a similar improved productivity could be achieved in the North Dakota Bakken if reservoir contact area could be maximized, this completion and stimulation strategy was initially selected.

Post Completion Evaluation The technical challenge of evaluating completion performance to optimize economics in the early phase of development is considerable. Some of the challenges faced were difficult petrophysical analysis, complex geology and extended transient flow periods. Technical analysis of complex reservoirs can be enhanced by a multi-tool approach. Each tool in isolation will result in a non unique match. However, by using consistent assumptions with several tools one can improve the uniqueness of the results. The approach taken by the Bakken team was to perform

1. Production analysis on every completion 2. Use reservoir simulation to match well performance

of each completion. 3. Obtain pressure transient test on each completion and

incorporate the results into the simulation history match

The aim of this work is to evaluate completion efficiency, reservoir property variation and effective drainage radiuses of the producing wells. The work also helps guide the decline curve analysis so as to enable reasonable ultimate recovery estimates to be made. Pressure transient tests were modeled to determine if a surface or downhole shut-in would be required to obtain analyzable results. The modeling work indicated that a surface shut-in would result in a test dominated by wellbore storage. Based on these results all transient tests are conducted with a downhole shut-in and have proven to provide very good results. Figure 16 is a log-log plot demonstrating the quality of the data obtained in the Bakken development and our ability to match the log-log response with the simulator. This information was used to help calibrate our simulation history match for each completion. Observations and Conclusions Achieving economic returns in a resource play can be challenging and requires careful planning and detailed evaluation. Too often these plays are considered “cookie cutter” developments where a winning formula is blindly applied with little technical analysis. This paper documents how the application of proven techniques of technical analysis provides insight, beyond simple statistics, to the entry and development stages in these plays. Vertical well performance provides valuable insight into the productive capacity of the reservoir. These results can be used to develop screening economics for the potential entry into

this development area and to set initial expectations for the development.

Nomenclature A = drainage area, ft² Bo = oil formation volume factor, RB/STB

ct = total compressibility, psi-1

h = reservoir thickness, ft k = effective permeability to oil, md

hk = effective horizontal permeability, md

vk = effective vertical permeability, md L = horizontal well length, md pwf = bottomhole producing pressure, psia pi = initial reservoir pressure, psia

ep = pressure at the drainage radius, psia pwD = dimensionless wellbore pressure q = oil flow rate, B/D

hq = oil flow rate, B/D QDA = dimensionless cumulative production based on area Q = cumulative oil production, B re = outer radius, ft reh = horizontal well drainage radius, ft rw = wellbore radius, ft φ = porosity, fraction μ = viscosity, cp π = 3.14159

Subscripts i = initial o = oil

t = time Acknowledgements The authors would like to thank Marathon Oil for their support and permission to publish this study. A special thanks to Jim Williamson for his excellent technical support.

References 1. North Dakota Industrial Commission, Department of

Mineral Resources, Oil and Gas Division, available from World Wide Web: http://www.dmr.nd.gov/oilgas

2. Lantz, T., Greene, D., Eberhard, M., Norrid, S., and Pershall P.: ”Refracturing Treatments Proving Successful In Horizontal Bakken Wells; Richland Co, MT”, SPE 108117 presented at the SPE Rocky Mountain Oil & Gas Technology Symposium, Denver, CO, Apr (16 -18, 2007)

3. Agarwal, R.G., Gardner, D.C., Kleinsteiber, S.W. and Fussell, D.D.: “Analyzing Well Production Data Using Combined-Type-Curve and Decline-Curve Analysis Concepts,” SPEREE (October 1999) 478.

4. IHS Energy services available from World Wide Web: http://www.energy.ihs.com/solutions/regions/us

5. Joshi, S.D.:, Horizontal Well Technology, PennWell Publishing Company, Tulsa, (1991). 6. Wiley, C., Barree, B., Eberhard, M., and Lantz, T.:

“Improved Horizontal Well Stimulations in the Bakken Formation, Williston Basin, Montana,” SPE 90697 presented at the SPE ATCE in Houston, TX (Sept 26-29, 2004).

7. Eberhard, M.: Halliburton, Personal Communications.

6 SPE 114171

Porosity, % 4Permeability, mD 0.0003 - 3.36Swi, % 30 - 60h, ft 30.00API 42.00Viscosity, Cp 0.36Gas Gravity 1

Probability IP, BOPD (30D) EUR, MBO Drainage Area, AcresP10 45 99 125P50 442 422 389P90 2085 881 826

Table – 1 Typical North Dakota Bakken Properties

Table – 2 Simulation Results

Figure 1 – Initial Production for Historic Bakken Wells

SPE 114171 7

UPRC: Andecker 44-34 #133-025-00456

T146N-R94W sec 34

LBS

UBS

10700

Upper Shale

Middle Bakken

Lower Shale

Figure 2 – Projected EUR for Historic Bakken Upper Shale Completions Figure 3 – Type Log

8 SPE 114171

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Figure 4 – Example of North Dakota Bakken Pilot Hole Core

Figure 5 – Type Curve of Production by Vintage (Inc. Montana)

Re-frac

SPE 114171 9

0

20

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0 20 40 60 80 100 120 140 160 180 200

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Figure 6 – Type Curves for Vertical and Horizontal Completions in the Bakken Formation

0

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0 1 2 3 4 5 6 7 8 9Effective Drainage Volume (MM bo)

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ulat

ive

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abili

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Figure 7 – Effective Drainage Volumes for Each Completion

10 SPE 114171

Bakken Shale

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Figure 8 – Production Analysis Based Flow Capacity Estimate Figure 9 – Projected EUR

SPE 114171 11

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Figure 10 – Horizontal Permeability Distribution

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Figure 11 – Distribution of Initial Production

12 SPE 114171

Figure 12 – Eclipse Model Example Grid Design

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Figure 13 – Eclipse Simulation Profiles

SPE 114171 13

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Figure 15: Comparison of cumulative production normalized to drilled lateral length for various Bakken completion types

14 SPE 114171

Figure 16 – Well Test Pressure Build Up Log-Log Analysis