Horizontal recompletions provide the avenue to attractive economics, even in this depressed commodity price environment.
by Clay Terry & William Ruhle
April 8, 2016

Since the early combination of modern horizontal drilling and hydraulic fracture technologies in the Sleeping Giant project in Richland County, Montana, drilling and completion practices have continuously evolved. With modest beginnings, this project ultimately became known as the Elm Coulee Field. It has since produced 149 million stock barrels (MMSTB) of high-quality crude, a leader among several fields in the Bakken and Three Forks Formations of the Williston Basin. With more than 12,000 horizontal wells drilled and completed in the Bakken/Three Forks petroleum system1, a significant percentage of existing horizontal wellbores had suboptimal completions. This could be attributed to any of the following factors:

  • Short lateral extent
  • Vintage wellbore construction that did not exploit modern methods unavailable at the time of completion
  • Problematic well circumstances, such as breaches in wellbore isolation
  • Suboptimal number of fracture stages or spacing compared with current design
  • Low completion efficiency along the lateral attributed to ineffective fracture stimulation of each formation entry point
  • Insufficient fracture conductivity of primary treatments (for example, low fracture conductivity associated with slickwater treatments used in liquids-rich reservoirs)

Additionally, 60 to 70 percent of existing horizontal wellbores in the Bakken/Three Forks system are not contributing to well production.2, 3, 4 Considering this information and the current low price of oil, important questions arise regarding motivation for continued activity rather than waiting until commodity prices improve.

  • Why should operators expend capital in this sub-$65/barrel of oil equivalent (BOE) environment rather than wait until prices improve?
  • What options do operators have to increase value in this downturn?
  • Are these options economically competitive for stakeholders with similar performance during the past five years?

Many well reviews have already created compelling cases for investing in recompletion efforts for horizontal wellbores. These recompletion jobs take advantage of existing wellbores with drilling and primary completion expenses considered to be "sunk costs," eliminating such costs as part of a project investment consideration. Recompleting many existing wellbores can provide significant opportunities for enhancing wellbore production, potentially adding new reserves at an improved unit cost of production compared to virgin well construction metrics.

Refracture, Re-Entry & Remediation

Horizontal recompletions can be categorized as refracturing, re-entry or remediation. A refracture is a secondary fracture treatment after a period of producing time. A refracture service is applied to access underperforming or noncontributing portions of the reservoir, usually without mechanical zonal isolation. This helps increase percentage contribution from the overall lateral and reservoir drainage efficiency. Re-entry operations often feature two techniques. One type is a recompletion operation that installs a liner and modern completion in an original openhole wellbore. A re-entry operation could also be a side-track operation designed to redrill and complete an existing well with a new lateral arm. A remediation is an application where the primary completion experienced a design failure, preventing the initial fracture treatment program from being completed as designed. For example, in a well that experienced mechanical damage during the primary completion, the lateral can be reperforated and treated with a refracturing service to stimulate reservoir area previously forfeited. Figure 1 illustrates 37 applications of one refracture service during 2013 and 2014, with 30 in the Rockies area and seven in the San Joaquin basin.

BRIEF DESCRIPTION OF IMAGEFigure 1. Wells by geological basin with refracture services (Graphics courtesy of Figure 1. Wells by geological basin with refracture services (Graphics courtesy of Halliburton))

Several operators recognize opportunities in their current portfolio of assets that have economic value even in today's market. Successful opportunities take advantage of proven technologies, best practices, and available equipment and skilled personnel in a highly competitive service sector to increase production. This will help improve average well completion efficiency, and often add reserves, at competitive economic levels to their own recent development costs in a higher commodity price environment. This article addresses practical opportunities for well operators to add productive capacity, arrest aggressive production decline rates and often increase economic ultimate recovery (EUR) through refracturing existing lateral wellbores. Compelling evidence exists to motivate an industry-wide focus on refracturing in this depressed commodity price market.

Case Study: Williston Basin

Candidate selection for this Bakken project began with the construction of a database of horizontal wells targeting the Bakken/Three Forks play. Reservoir quality was high-graded on metrics, including normalized production (BOE/feet of lateral) as well as gas-oil ratio (GOR) and water-oil ratio (WOR), with a focus on a known highly productive area—the Sanish Field in North Dakota. A simpler and more holistic method that benchmarks well productivity on 24-month cumulative oil production is illustrated in Figure 2. The histogram indicates the candidate acreage and wells are in the upper 50th percentile of the entire Bakken play. Underperforming wells can be identified by characterizing the production profile using decline analysis, pressure transient analysis and comparatively lower production.

Figure 2. Benchmark of well performance by cumulative production (normalized to 10,000 feet lateral length)Figure 2. Benchmark of well performance by cumulative production (normalized to 10,000 feet lateral length)

The refracture project had four wells in several drilling spacing units. The economic assessment of a refracture project should encompass a group of wells large enough to quantify the average production uplift. This project incorporated several well histories. Well 1 was a suboptimal completion attributed to 2008 vintage well construction practices. Well 2 was a more modern completion in 2010 with high initial production behavior and steep, hyperbolic decline. Both Wells 1 and 2 were offsets in the same unit with drill spacings of approximately 1,800 feet between wellbores. Well 3 was a candidate to perforate new pay in the heel portion of the lateral where the pre-existing perforations and an additional eight stages in new pay were treated with a refracturing service. Well 4 was refractured commensurate with a new infill completion within the drilling space unit (DSU). The need to provide protection for existing wellbores when planning for an offset new infill well completion often adds sizable costs to that new completion. In such cases, the additional cost to refracture the existing wellbore during the same operation is often seen as minimal compared with fracture protect costs for the infill well. Therefore, the net expenditure to refracture is effectively lower when it is needed due to infill drilling. It can also provide a method for mitigating production losses in the existing wells caused by well bashing from infill stimulation.5, 6 The refracture designs consisted of multiple cycles of proppant separated by using a refracturing service, placing approximately 1.5 MM lbm of proppant in each well. All the refractured wells experienced significant uplift in terms of production compared with the baseline forecast, ranging from 56 to 286 percent incremental production at six months. In addition, all of the refractured wells exhibited arrested declines and reduced GOR, indicating stimulation of reserves that were not previously being drained efficiently. Offset wellbores were also observed. In several of the cases, the DSU as a whole experienced a marked increase in well productivity after the refracture treatments of the study wells. Neighboring wells within the DSU also observed up to 30 percent uplift in productivity. Figure 3 is a plot of the total oil production rate for all four wells refractured in the project. An incremental increase of 81.4 MSTB of oil was produced within the first 270 days after the refracturing operations.

Figure 3. Daily production rates for Sanish field refractured wells and offsetsFigure 3. Daily production rates for Sanish field refractured wells and offsets

Case Study: Denver-Julesburg Basin

Four horizontal wells drilled from the same pad location and within a single DSU of the Wattenberg Field in Colorado were refractured. This took place in the Codell, Niobrara formation, specifically the Denver-Julesburg Basin. The primary completions were conducted in 2011. Refracturing treatments were conducted on each well in 2013. The primary objective to achieving economically successful refracture treatments is to contact reservoir supplies that have not been previously drained. One stimulation service helps achieve this goal by diverting stimulation fluids at the fracture face with patented self-degradable materials that do not require mechanical intervention for isolation. The refracture service treatments were performed in multiple proppant cycles separated by refracture service diversion materials, which are tailored in real time during the treatment as a function of net pressure diagnostics. Even with a 263 percent uplift in oil production compared with baseline forecasts for the four-well Niobrara refracture unit, the GOR ratios for each well were significantly reduced. This supports the belief that the reservoir drainage area has been increased, providing both increased reserve estimates and accelerated production rates. At a four-well cost of $4.245 million (mid-2013 pricing), the projected increase in net present value (NPV) for the project exceeds $600,000 above costs based on current commodity prices.

Fracturing Services Procedure

Simply bullheading a refracture treatment into a well does not provide control of fracture placement and is one reason why some refracturing treatments, often aptly labeled "hail Mary fractures," are economically unsuccessful. One refracturing service process helps achieve a more effective distribution of hydraulic fractures by inducing diversion away from the existing fractures through an initial wellbore preparation step. The process mitigates leakoff into existing fractures and initiates fractures in portions of the lateral not previously stimulated. The refracture treatment program is pumped with a high intensity of proppant cycles to stimulate a higher proportion of the lateral and enhance fracture conductivity into the reservoir. Slurries containing patented self-degrading diversion materials are pumped intracycle to initiate new fractures. Proprietary pressure diagnostic tools are used to customize the diversion slurries in each cycle to maximize the stimulated reservoir volume. Figure 4 is an example of a refracture stimulation treatment in a Bakken formation well. The treatment consisted of a single, continuous fracturing operation, partitioned by a 23-cycle diverter drop procedure to effectively distribute proppant along the length of the lateral wellbore.

Figure 4. Refracture treatment with intracycle diversion in Bakken FormationFigure 4. Refracture treatment with intracycle diversion in Bakken Formation

Economic Impacts

Properly engineered refracturing applications have great potential for many operators who have early vintage horizontal wellbores. Other good candidates include wellbores exhibiting low completion efficiency behavior; wellbores that experienced well construction problems during the original drilling and completion; wellbores in which liner completions were never installed; and even wellbores that have developed production limitations attributed to mechanical integrity through time. The Bakken refracturing project showcased here resulted in significant production boosts over the projected baselines (65 to 226 percent cumulative uplift in 12 months), a reduction of production decline, reduced GOR and offset well production uplift in several of the DSUs within which the target wells reside. The Bakken refracture project total cost was $5.345 million, projects a 28-month payout, and a NPV of $2 million. The resulting internal rate of return (IRR) on invested capital deployed is 38 percent (2015 Energy Information Administration (EIA) strip at $52.15/STB). Most impressive is the marginal cost of production compared to historical development costs from new well construction. The Bakken refracture project marginal cost of production is $13,363/BOE/day compared to reported operator's average development cost of $48,480/BOE/day.7 This metric alone should motivate many operators to take a hard look at refracturing economics for their portfolio of wells. The ability to add production for less than one-third of the cost of normal development cost metrics provides high value for the average operator in this downturned market (see Figure 5).

Figure 5. Economic impact of refracture project in Sanish Field, North DakotaFigure 5. Economic impact of refracture project in Sanish Field, North Dakota

The question of why an operator should expend capital in this market is boldly answered by the results of these refracture programs The economics are impressive, and the marginal cost of production stands in stark contrast to the looming concerns of an industry reeling from sharp economic declines. Opportunities exist for well operators to add value, increase economic production and deliver impressive return on invested capital for stakeholders. Horizontal recompletions provide the avenue to attractive, if not superior, economics, even in this depressed commodity price environment.

References

  1. Hart Energy. 2015. Sonnenberg, Bakken and Niobrara Shales — The Play Book. Page 6.
  2. Lecampion, B., Desroches, J., Weng, X. et al. 2015. Can We Engineer Better Multistage Horizontal Completions? Evidence of the Importance of Near-Wellbore Fracture Geometry From Theory, Lab and Field Experiments. Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 3—5 February. SPE-173363-MS. http://dx.doi.org/10.2118/173363-MS.
  3. Slocombe, R., Acock, A., Chadwick, C. et al. 2013. Eagle Ford Completion Optimization Strategies Using Horizontal Logging Data. Presented at the Unconventional Resources Technology Conference, Denver, Colorado, 12—14 August. SPE-168693-MS. http://dx.doi.org/10.1190/URTEC2013-136.
  4. Miller, C.K., Waters. G.A., and Rylander E.I. 2011. Evaluation of Production Log Data from Horizontal Wells Drilled in Organic Shales. Presented at the North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, 14—16 June. SPE-144326-MS. http://dx.doi.org/10.2118/144326-MS.
  5. Barree, R.D.,Cox, S.A. et al. 2014. Economic Optimization of Horizontal Well Completions in Unconventional Reservoirs. Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 4—6 February. SPE-168612-MS. http://dx.doi.org/10.2118/168612-MS.
  6. King, G. 2014. 60-years of Multi-fractured Vertical, Deviated and Horizontal Wells: What Have We Learned? Presented at the SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands, 26—29 October. SPE-170952-MS. http://dx.doi.org/10.2118/170952-MS.
  7. JPMorgan. 2015. North American Equity Research, Jan 2015. http://www.jpmorganmarkets.com