Dynamic Reservoir Analytics Engineering Consulting

Well Spacing Comparison - Between Two Closest Producers

Based on the graph above, it appears that the recently drilled Spraberry wells are being developed on a tighter well spacing compared to the Wolfcamp completions. Lately because many operators prioritize drilling the most productive target zones, less than optimal resource recovery of the commercial hydrocarbon reserves is observed throughout the basin. To address this issue and increase the reservoir recovery, stacking, staggering, and drilling on tighter well spacing requires a more comprehensive understanding and detailed planning by the asset teams.

The Permian Basin is known for its impressive stacked pay, which is considerably greater than what is seen in other unconventional plays. The hydrocarbon column being developed in the Midland and Delaware Basins is over 2,000 feet thick, compared to 300 feet and 500 feet in the Williston Basin and Eagle Ford Play in South Texas. In the study area, 79 wells were stacked/staggered or drilled within less than 100 feet away from each other in the same formation, with 38 of these producers drilled in the recent 2022-2023 years. However, because of the well proximity to each other and potential absence of the flow barriers between zones, the development of the stacked wells poses challenges such as potential risk of well interference and fracture hits. The distribution graphs above are Peak Monthly Rate, Peak Monthly Rate Normalized for the lateral length (barrels of oil per 100 ft), and Six Month of Cumulative Production Normalized also for the lateral length (barrels of oil per 100 ft) grouped by stacked/staggered and non-stacked wells. Based on the data, it appears that wells that were stacked/staggered or drilled at tighter well spacing (less than 100 feet) are less productive. Additionally, the recently stacked/staggered wells are not performing as well as the older original stacked/staggered producers. In the study area, both Spraberry and Wolfcamp formations have stacked/staggered wells that were drilled and came online at the same time. There is no "parent" and "child" relationship between them. 18 out of 38 stacked/staggered wells were drilled in close proximity (less than 200 feet) from the already existing producers in the same zone. The possibility of well interference needs to be addressed to make sure that these wells are not experiencing typical reduction in EUR potential caused by the infill drilling. The analysis shows that there is no significant difference in GOR between the different groups of wells, suggesting that the wells were not drilled in higher GOR zones or areas. Further analysis and investigation may be required to identify potential issues with the reduced productivity performance.

Regional Geology - Spraberry and Wolfcamp Formations

Siltstones, very fine-grained sandstones, mudstones, and argillaceous limestones comprise Spraberry formation. The Spraberry formation is a naturally fractured reservoir with low porosity and low matrix permeability. These qualities, along with a natural fracturing tendency, provide migration paths and a trap for hydrocarbons. Factors controlling reservoir quality can be divided into depositional and post depositional. Depositional influence includes original rock materials, sorting, mineralogy, presence of clays and also sedimentary structures such as burrows. The impact of diagenetic features such as compaction, cementation, mineral dissolution, and fractures also contributed to changes in reservoir quality. Many of the siltstones are laminated and mixing with sandstones frequently, reducing overall reservoir quality. However, more massive sandstones occur, most often in stacked or amalgamated channels. Thin, laterally continuous black shales with high TOC content are also present. Based on the regional stratigraphic correlation and percentage of sandy content, the formation consists of three genetic stratigraphic sequences, known as the Spraberry Upper, Middle, and Lower benches. The Upper and Lower benches have thicker and more widely spread siltstone and fine-grained sandstone layers with intermitted silty shale, whereas the Middle bench is composed of the calcareous shale, limestone, and thinner more locally developed fine-grained sandstones, The Spraberry formation appears to represent a large scale, basin floor submarine fan system consisting of stacked fan series. Fan deposits are cut by a succession of the narrow channels comprised of the clastic flow material. The fine grained and mud rich fan complex of the Spraberry is found to have an abundant sediment supply through its extensive network of leveed channels. The Spraberry formation represent a distinctive depositional system, wherein carbonate sediment is mainly generated and conveyed throughout the basin during sea level highstands and clastic sediment is deposited during sea level lowstands. Porosity measured varied from 2 percent in rocks with poor reservoir quality such as the argillaceous siltstone and mudstone while good reservoir rocks had an average porosity of 9 percent. The low permeability can be attributed to such factors as presence of illite in pore space, silt size particles in pore throats, diagenetic effect, quartz overgrowth, and presence of calcite in pore spaces. The entire section from the top of the Spraberry to the base of the Dean varies in thickness between 1,200 and 1,870 feet. The average depth of the top of the Spraberry formation is approximately 6,800 feet across the entire sub-basin.

Spraberry Upper Unit

Neutron porosity ranges from 7% to 22%

Density ranges from 2.44 to 2.60 g/cm3

Estimated TOC ranges from 2% to 8%

Deep resistivity ranges from 20 to 290 Ohm-meter 

Spraberry Middle Unit

Neutron porosity ranges from 6% to 20%

Density ranges from 2.45 to 2.61 g/cm3

Estimated TOC ranges from 1.2% to 7%

Deep resistivity ranges from 12 to 275 Ohm-meter 

Spraberry Lower Unit

Neutron porosity ranges from 5.5% to 16.5%

Density ranges from 2.48 to 2.62 g/cm3

Estimated TOC ranges from 1% to 7%

Deep resistivity ranges from 14 to 260 Ohm-meter 

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The Wolfcamp formation is generally a complex unit consisting of two-lithology based system of mostly shale with interbedded limestone. Minor layers of calcareous sandstone are present. This formation is separated into four units known as the Wolfcamp A, B, C, and D. The four zones of the Wolfcamp formation display different characteristics in terms of lithology, fossil content, porosity, TOC, and thermal maturity. Depth, thickness, and lithology vary significantly across the basin. Depositional and diagenetic processes control this formation’s heterogeneity. The average permeability is as low as 10 millidarcies. Shallow-water shelf facies consist of mixed shale, carbonate, and lime mudstone. Basinal sediments include dark shale, lime mudstone, and carbonate debris. Carbonate detritus from the shallow shelf was delivered to submarine valleys and formed a succession of fan systems. Fan deposits are cut by a series of narrow channels consisting of clastic flow material also derived from the shelf. The presence of deep water dark organic rich shales interbedded with siliciclastic sediments indicates that debris and channel deposition advanced into the area during times of sea level lowstand. It is interpreted that the majority of gravity flows occurred during lowstands of relative sea level. During sea level lowstands, platforms were exposed, and siliciclastic material was conveyed directly into the basin. During sea-level highstands, sediment input to the basin comprised platform-derived carbonate, aeolian silt, and clay. A siliciclastic series includes the lower Wolfcamp interval. This low stand interval contains submarine fan deposits that extend across the basin floor. The lower Wolfcamp interval forms west and north thinning wedge of siliciclastic sediments transported from highland source areas to the east and south. A calcareous series includes the upper Wolfcamp interval. This highstand interval contains widespread alternating layers composed of calcareous mudrock and detrital carbonate deposits. Calcareous layers are predictably thicker near the platforms that provided the carbonate detritus. In the central parts of the basin, calcareous intervals are mudrock dominated and include thin and permeable reservoir of coarse-grained siliciclastic material. The carbonate turbidites display TOC values ranging from 0.6 to 6 percent, whereas the siliciclastic turbidites generally exhibit less than 1 percent. The interbedded non-calcareous mudstones contain as much as 8 percent TOC. Wolfcamp thickness ranges from about 800 ft to more than 7000 ft in the Delaware Basin. The Wolfcamp formation is the deepest in the center of the basin, measuring approximately 12,000 feet deep, whereas towards the edges of the basin, it is found at a much shallower depths varying from 4,000 to 7,000 feet. 

​Wolfcamp A Unit

Neutron porosity ranges from 7% to 22%

Density ranges from 2.45 to 2.60 g/cm3

Estimated TOC from 2% to 8%

Deep resistivity ranges from 20 to 290 Ohm-meter 

Wolfcamp B Unit

Neutron porosity ranges from 6% to 20%

Density ranges from 2.45 to 2.61 g/cm3

Estimated TOC ranges from 1.2% to 7%

Deep resistivity ranges from 12 to 275 Ohm-meter 

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A primary controlling factor that affects the high rock brittleness index is composition of the material. For example, clay or mudstone tend to be more flexible and ductile. Quartz and calcite on the other hand, with a higher density and hardness, are more brittle. In general, the siliciclastic-rich sequences exhibit the highest brittleness index and therefore geomechanical competence.

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Please refer to three geological reports about Midland Basin that include structure and thickness maps, depositional environment explanations, lithology and mineralogy studies (click on these links: U.S. Energy Information Administration, Enverus Blog, ProQuest Research).