Despite the slight downturn in activity observed in the beginning of the first quarter of 2016, the Wolfcamp Formation of the Permian Basin appears to be back on a record-setting trend in the first quarter of this year with issued permits to be at or near 2,000 wells. Whether from new operators entering the area or seasoned Permian players developing acreage, this increased activity is met with a variety of challenges for all operators. One of those challenges is the effect that the existing natural fracture network will have on completion design and ultimately production.

The Wolfcamp Formation is primarily a basin structure located in West Texas and extending into the southeast portion of New Mexico. As part of the Permian Basin, it is estimated to cover 1 million acres at a depth of 2,133 m to 3,657 m (7,000 ft to 12,000 ft). Comprising primarily the shallower Midland and deeper Delaware sub-basins, the formation is geologically dominated by silty shale (mudstone) interbedded with detrital limestone. Originally deposited during the Permian Period (299 million to 280 million years ago), the formation has been uplifted, resulting in numerous faults and natural fracture networks.

While this natural fracture network is characteristic of the Permian Basin overall, and specifically the Wolfcamp Formation, the significance and severity vary when moving throughout the formation. Some areas will have very few effective natural fractures while other areas see high permeability streaks or faulting (generally characterized as a darcy level of magnitude higher than the target interval). High concentrations of natural fractures, commonly referred to as swarms, are generally characterized as one natural fracture per 6.1 m to 9.1 m (20 ft to 30 ft) laterally over a 60.9-m (200-ft) interval.

The key is understanding the effect of those fractures and the impact they will have on the completion. Though operators are adjusting to the new price environment and pushing the envelope, a focus on cost efficiency and profitability is stronger than ever. The goal is not simply just production growth anymore. In today’s market where the emphasis has shifted to return on invested capital, operators must quickly gain an understanding of the unique factors impacting costs and production in their acreage and then quickly make informed decisions to maximize profitability.

Strategic approach

To assist in the determination of the effects of the fracture network, successful operators have proactively addressed natural fractures by utilizing diagnostics when developing drilling and completions programs.

ProTechnics has established the approach of partnering with oil and gas operators to develop strategic diagnostic plans, addressing specific challenges when hydraulically fracturing wells. When designing completions around natural fractures, the company pairs its Global Technology Team’s basin experience of 1,600 wells in the Wolfcamp Formation alone with each operator’s specific field knowledge to implement an optimal diagnostic plan.

A strategic approach typically starts with evaluating the current or anticipated drilling program and completion design. Evaluating core data, formation targets or problems encountered during drilling, such as fluid loss, provides an understanding of the reservoir description to consider when designing the completion. Then leveraging basin knowledge and trends, optimal completion design and a diagnostic program can be developed. This approach shortens the learning curve to eliminate excessive completion costs while maximizing the amount of stimulated reservoir volume.

Informed decisions

FlowProfiler water and oil tracers are used as a means of simultaneously evaluating both fracture fluid cleanup and hydrocarbon production over time. Unique tracers injected with each fracture stage are sampled during flowback and production, providing a quantitative dataset from which to quickly evaluate the effectiveness of the completion design in a brief period of about 30 to 60 days. The use of fluid tracers has greatly increased the understanding of geologic trends within the Wolfcamp Formation as it pertains to natural fractures or faults and how to effectively consider them when designing completions.

Initial completion designs utilized in the Permian Basin called for geometric stage spacing across the full lateral without any consideration of natural fractures or faults that intersect the wellbore. Cases 1 and 2 show the effect that faults and high permeability streaks have on the well performance when ignoring or designing around natural fractures, respectively.

Case 1 is an example of the typical response observed when the fault intersected the well at roughly 90 degrees, dissecting the wellbore between Stages 7 and 8 in this case (Figure 1). As evident in the data presented throughout the sampling of the well, the operator had nonproducing intervals where the fault intersected the wellbore, resulting in neither water-based nor oil-based tracers giving any indication of fluid entry.

As fault trends became evident across the basin areas, operators began to exclude those stages from their designs in areas known to have nonproducing fault trends. Case 2 is a prime example of a typical design that had a known nonproducing trend (fault) across the middle of the drilled lateral (Figure 2). Case 2 had a fault intersecting the wellbore at roughly a 90-degree angle in the vicinity of what would have been Stage 15 midway through the lateral. Based on trends for the area, an optimal standoff distance was applied to the design, skipping the faulted interval while all remaining stages were stimulated with the standard design. As the well was opened to flow, the remaining stages indicated good productivity and displayed no adverse effects from the known fault.

Ultimately the lessons learned from strategically designing completions around existing natural fracturing led to abandoning stages across known faults where zero or very minimal production had been observed. The result was lowering completion costs by the equivalent of two or three stages, or $300,000/ well at current prices, without sacrificing the ultimate recovery on an overall lateral-foot basis. While it is also important to note that the two case wells presented show faults intersecting the wellbore at approximately 90-degree angles, in other instances faults crossed the wellbores at more obtuse angles and required varied standoffs from the faults and greater influence in the subsequent stages on either side of the faults. Understanding the nonproductive intervals across the basin is critical to shortening the learning curve, maximizing stimulated pay while improving operational efficiencies.

The road forward

As operators continue to understand the effects of natural fractures, learnings are not just applied to single-well applications but are progressing to fieldwide development.

In underdeveloped areas, some operators are finding a benefit to the natural fractures. ProTechnics developed an application for identifying and targeting these natural fractures through an engineered completion design using SpectraStim proppant tracer data in conjunction with a SpectraScan spectral gamma log. Depending on the area and data analysis, how to best target the natural fractures to maximize stimulated reservoir volume varies from perforating at the fractures to targeting an optimal distance nearby. In other instances, the application is used as a measurement of reservoir quality to better understand the impact different reservoir descriptions have from well-to-well or in layer-to-layer communication.

In more developed areas, operators are beginning to focus on the effect of natural fractures in parent-child well interactions. With the presence of natural fractures being a given, the question becomes, “What do we do about it?” Additional pressure mitigation techniques include far-field diversion as well as programs for determining when to shut in offset wells during infill programs.

As more data become available and a clearer picture emerges of the impact natural fractures may have in each area across the basin, operators are beginning to characterize problem faults and developing infill programs around them. Knowledge is extended from a localized, single-well application to a broader pad and field development, driving operational and production decisions for fracture order and pressure mitigation.

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