Malpani, Raj (Schlumberger) | Alimahomed, Farhan (Schlumberger) | Defeu, Cyrille (Schlumberger) | Green, Larrez (MDC Texas Energy) | Alimahomed, Adnan (MDC Texas Energy) | Valle, Laine (MDC Texas Energy) | Entzminger, David (MDC Texas Energy) | Tovar, David (Schlumberger)
As well density in a section increases, drilling and completions decisions regarding the stimulation of infill wells are increasingly informed by changes in the in-situ stress, mechanical properties, and material balance that result from depletion around parent wells. This is a multifaceted reservoir-dependent four-dimensional problem with many different dependencies. Accordingly, projects involving parent-child interactions during the completion phase are carefully planned using sound engineering principles to avoid negative effects of depletion and fracture hits. We present a case study from a section development in the Wolfcamp formation. Multiple wells drilled at various times are chronologically described below:
1) Parent well in the middle of the section – generation I
2) Child well 1 to the western edge of the section (2 months after parent well) – generation II
3) Child well 2 to the eastern edge of the section (2 months after child well 1) – generation II
4) Child well 3A between parent well and child well 1 (6 months after child well 2) – generation III
5) Child wells 3B, 3C, and 3D (drilled from the same pad) between parent well and child 2 (6 months after child well 2) – generation III
All wells but child 3D are in the same horizon. Downhole and surface gauges were installed on all observation wells during the completion infill wells (child 3A, 3B, 3C, and 3D). Water injection treatment was performed on the existing wells (parent, child 1, and child 2) wells prior to completing generation III infill wells. Child well 3A was completed first to build up pressure on the west side of the section. Child wells 3B, 3C, and 3D were from same pad on the surface and were zipper fractured. Design changes were made to the completion program with contingencies built-in to make additional changes on the fly to incorporate field geometry control aids and reduction to injection rate and fluid volume.
The parent well experienced fracture hits during completion of child 1 and child 2, spaced at ~2,500 ft. Chemical tracers and production behavior suggested that even a few months of production led to pressure reduction in the section. During completion of child wells 3A, 3B, 3C, and 3D, multiple pressure increases were observed on the parent and child 2 wells with varying degree of severity, but no fracture hit. The stress buffer (shadow) created by carefully sequencing the stimulation program aided in reducing the fracture communication. The fluid injection strategy was effective in reducing the magnitude of pressure communication. Additionally, an active pressure-monitoring program and real-time design changes were able to prevent fracture hits.
The tracer data and productivity index (PI) profile suggest that during stimulation, wells have been hydraulically connected; even though the connections fade over time, results in overall of lowering of reservoir pressure. Some sections do show abnormal behavior likely due to localize geological features. The initial PI for the child 3A, child 3B, and child 3C is smaller than that of the parent well, like child 1 and child 2 wells. All wells in Wolfcamp A shows similar PI profile after all the wells were put back on production, except for child 3A. Child 3D well (Wolfcamp B) has higher PI than other generation III wells pointing to no or minimal communication between the two formations. The infill wells (generation III) have increased water cut than the existing wells (generations I and II). Child 3D well is in Wolfcamp B, which has higher water saturation as compared to Wolfcamp A in the area.
Wells with spacing above 1,000 ft show equivalent productivity, but wells less than 500 ft apart show inferior productivity. The optimum well spacing with the general completion and stimulation design in the area seems to be within 500 ft to 1,000 ft (5 to 10 wells in a section) in this area in Wolfcamp A. The results also suggest that hydraulic connectivity from Wolfcamp B to Wolfcamp A but the production seems to be isolated from Wolfcamp A. Developing a section with depletion effects occurring at various distances and durations is challenging. Our proactive approach of designing, monitoring, and responding provides insights into the development of multigeneration wells in the Wolfcamp formation and in similar settings around the world.
As unconventional plays in North America mature, understanding the performance of step-out and infill wells becomes increasingly important. “Child” well performance has become a major topic of interest because in every unconventional play there exists a significant portion of child wells that perform worse than their “Parents”. It is important to understand how child wells are likely to perform across a play so that engineers can properly forecast production and organizations can allocate capital correctly. The objective of this study was to establish an efficient scoping workflow for understanding the effect of depletion on child well performance across an area of interest, so that promising infill locations can be recognized, and risky infill locations avoided.
The problem with the current parent-child paradigm is that it requires explicitly defining what constitutes a parent, or conversely a child. As described in this study, the choice of definition immediately introduces bias into the interpretation of child performance. A simple function was developed to express the parent child relationship as a continuum, where the influence of parents on a given reference well decays with distance. A workflow was then established to apply the function across a large public well dataset. The workflow handles stacked development, accommodates large scale geological variation and can be efficiently applied over a significant number of wells.
The workflow was applied to areas of interest within the Montney formation in the Western Canada Sedimentary Basin. Results indicate that the depletion function can describe well performance in many areas of interest. Child performance heat maps were generated to identify potential opportunities for infill development. The workflow was also employed to detect performance outliers which could be further investigated to understand child well optimization.
Recent studies have indicated that a substantial percentage of wells “Children” in unconventional plays perform worse on a completion-normalized basis than their predecessors within a defined distance “Parents” (Lindsay et al. 2018). One of the main reasons cited for poorer than expected performance of Child wells is depletion (Cao et al. 2017, Lindsay et al. 2018, Shin and Popovich 2017). Depletion in the vicinity of the child well has the following effects:
Frac-driven interactions (FDIs), more commonly known as frac hits, are becoming increasingly common as operators develop acreage near existing wells. These FDIs are commonly observed in an area of infill drilling in eastern Reagan County, Texas. To better understand their effects, a study was undertaken to document all FDIs observed during five years of field development in a fifteen-square-mile area. FDI frequency and intensity was found to be a function of (a) the parent well’s wellbore geometry, (b) offset direction between the parent and child well, (c) the presence or absence of a horizontal “buffer” well, and (d) distance between the parent and child wells. Horizontal parent wells received FDIs with greater frequency and intensity than vertical parent wells. Similarly, vertically stacked or directly offset parent wells received FDIs with greater frequency and intensity than indirectly offset or horizontally in-line parent wells. Horizontal parent wells commonly attenuate (or “buffer”) FDI frequency and intensity for other parent wells behind them (relative to the frac job). Distance between the parent and child well was found to have a strong negative correlation with FDI frequency and intensity but is more pronounced for vertical parent wells than horizontal parent wells. The majority of parent wells were found to receive either small FDIs or no FDI at all; thus, FDIs do not appear to pose a major risk to reserves within the study area contrary to many other unconventional plays. Although simple, the methodology was found to be a useful tool for understanding complex relationships between parent and child wells and may be applied to other development areas.
With the better understandings of well performance mechanisms from unconventional reservoirs and maturing technologies in drilling and completion, the industry has started realizing there could be significant potential value in those reservoirs. Improper development may leave significant resources unrecovered and significant value unrealized. The full field development concepts such as “tank” or “cube” developments are being implemented in the Permian Basin to maximize the asset value from developing those reservoirs. The paper first summarizes our analysis results of three full field developments implemented by three operators in the Northern Midland, and the paper presents optimal full field development plans (FDPs) in the Southern Midland Basin with our systematical workflow.
After we systematically review the main drivers of completion designs on the well performance and recovery efficiency, we then focus on a case history study we performed to compare the field development plans implemented by three operators in the same geologically similar area, including the well spacing and placement patterns, well completion designs, completion efficiency analysis, and corresponding well performance. We also performed long-term production forecast and economic analysis for those three field developments. Inspired by the outcome of the case history study, we then developed a systematic way (workflow) to optimize FDPs for any given unconventional reservoir.
The paper will illustrate the application of our workflow into the Wolfcamp formation in the Southern Midland Basin. We first build the numerical reservoir performance models based upon geological and reservoir properties, and calibrated those models with completion and well production history; We then assembled 155 different FDPs by combining different vertical and lateral well spacings and multiple completion designs; Next, we used those calibrated models to study the resource recovery and economics from those FDPs. Finally, we performed a sensitivity analysis of well cost structure and completion efficiency on the asset development values of those FDPs, from which an optimal FDP was proposed.
Based upon those two case studies, we observed that there is a sweet spot for well spacing and corresponding well completion design to maximize development value for a given reservoir. The study results also demonstrate that sub-optimal completion designs and well spacings could leave significant resource and values behind. Our study indicates that the drilling and completion cost structure and operation efficiency are very critical to realize potential value. Those two case studies show that the operator economic key driver, (such as Rate of Return Vs Net Present Value), will drive very different full field development decisions.
We are utilizing our workflow to study the optimal full field plan in the Delaware Basin. The workflow can be easily applied to optimize full field development plans to maximize the asset value for any unconventional reservoir, which may also minimize the number of pilot tests and parent-child well situations.
Growth in a number of newly drilled wells in unconventional reservoir development results in tightly spaced horizontal wells, which consequently creates well interference (fracture hits) between parent and infill wells as a result of stress redistribution from localized pressure sink zone in parent wells. This directly affects the production performance of both parent and infill wells. In order to minimize this effect, it is sometimes more preferable to place an infill well in a different pay zone. However; due to poroelastic effect, pressure depletion from the parent well also affects stress distribution in different pay zones and yet only a few literatures focus on this effect. The main objective of this paper is to predict temporal and spatial evolution of stress field for Permian basin using an in-house 3D reservoir-geomechanics model and propose guidelines for determining lateral and vertical drilling sequence of infill wells to mitigate well interference.
Embedded discrete fracture model (EDFM) is coupled with a sequentially coupled reservoir-geomechanics model to gain capability in simulating complex fracture geometries and high-density fracture system. Different scenarios with and without natural fractures were studied including a case where two parent wells are located in different layers (Wolfcamp A2 and B2) and a case where two parents are located in the same layer (Wolfcamp A2 and B2). Stress redistribution is then observed to determine the completion sequence of infill wells in different layers.
Producing two parent wells in the same pay zone results in large stress redistribution mostly in the area close to fracture tips at an early time. As time progresses, stress redistribution area becomes larger and covers almost entire infill well zone in Wolfcamp B2. Stress changes can also be observed in Wolfcamp A2 and A3 despite producing wells are only located in Wolfcamp B2. However, when producing two parent wells in different pay zones, stress redistribution can only be observed near fracture tips in both Wolfcamp A2 and B2 with minimum stress change in the infill zone even at a later time in all Wolfcamps A2, A3, and B2. This allows the possibility of producing infill well in the un-depleted layers (i.e. A3) enhancing efficiency of infill well completion. Fracture penetration and larger fracture length also play a significant effect in stress reorientation and evolution. Presence of natural fractures causes stress reorientation to occur at an earlier time due to higher depletion rate. This paper presents the possibility of changing the sequence of stacked pay from lateral well layout to vertical well layout in order to mitigate well inference and improve production performance of both parent and infill wells. Less stress change in the infill zone for vertical well layout makes it become superior to lateral well layout in which large stress redistribution can be observed.
The main goal for an operator developing an unconventional reservoir project is to maximize NPV per acre by optimizing its completion strategy. This can be achieved by applying a comprehensive approach that accounts for key well treatment controlling parameters, their impact on the future production performance, and economic uncertainty. In this work, we developed and applied a workflow to explore the impact of various completion parameters and determine the completion strategy with the maximum economic gain.
The workflow integrates petrophysical well log and core data, along with PVT lab experiments with normalized permeabilities calculated from microseismic attributes to initialize the reservoir model. The reservoir model is then calibrated using actual field data to generate a history matched model. Since this model is developed based on microseismic data and represents a realistic network of fractures created during stimulation, it can be further used to analyze the impact of main completion parameters, well spacing and configuration, on the production performance of the wells.
The workflow is applied to three wells drilled in a gas reservoir in the Marcellus Shale. Because abundant field data were available, we can be certain that the calibrated reservoir model accurately matches the reservoir behavior. Detailed analysis of the reservoir model shows the presence of undepleted zones which indicates the current well spacing is too wide. However, the frac hits recorded through microseismic monitoring and pressure interference with nearby wells suggests a tighter well spacing will result in energy loss and over-stimulation. Therefore, an economic analysis is used to evaluate the various well spacing and configuration scenarios and their implications in terms of cost-benefits.
Various well spacing scenarios are created for the original and the proposed chevron pattern well configurations. For each scenario, the EUR, NPV per well, and NPV per acre are calculated to represent maximum gas production, the overall profitability of the pad, and the economic success of the project, respectively. Three gas price scenarios are used for calculation of the NPV's to analyze the impact of the market condition on the economics of the project. The analysis demonstrates that tighter well spacing, independent of gas price, leads to the improved NPV per acre, reduction of EUR, and an increase in well communication as shown by the newly developed well communication index. The models reveal that a monotonic relation between well spacing and NPV per acre does not exist due to the complex nature of the created fracture network and competition between two opposite factors: frac hits that arises at tighter well spacing and unstimulated zones that diminish.
We showed that obtaining optimized well spacing and configuration could only be achieved through applying a comprehensive workflow that not only accounts for the impact of various well design and configuration parameters on production but also their economic implications defined in terms of NPV per acre. It is important to note that the integration of microseismic data was essential for the success of the workflow since it provides a realistic picture of the pathways connecting the adjacent wells which facilitate well communication.
Ursell, Luke (Biota Technology) | Hale, Michael (Novo Oil & Gas LLC) | Menendez, Eli (Novo Oil & Gas LLC) | Zimmerman, John (Novo Oil & Gas LLC) | Dombroski, Brian (Novo Oil & Gas LLC) | Hoover, Kyle (Novo Oil & Gas LLC) | Everman, Zach (Novo Oil & Gas LLC) | Liu, Joanne (Biota Technology) | Shojaei, Hasan (Biota Technology) | Percak-Dennett, Elizabeth (Biota Technology) | Ishoey, Thomas (Biota Technology)
Subsurface DNA is an emerging independent diagnostic offering oil and gas operators a high resolution and non-invasive measurement of fluid movement in the subsurface. DNA sequencing methodologies that use subsurface DNA markers acquired from well cuttings and produced fluids are being increasingly used in the Permian Basin to elucidate drainage heights for new and existing wells with increased temporal and spatial resolution. Drainage height estimates are applied across the asset lifecycle during appraisal, development, and production. We present a new exploratory application for DNA Diagnostics in the Midland Basin as a complementary data set for understanding reservoir characteristics when existing wells and data are not available.
In this work, Novo Oil and Gas and Biota Technology performed a study on an exploratory well in the Meramec formation of Ector County. Well cuttings were collected from a pilot hole to create a vertical DNA baseline through key Barnett and Meramec formations, and from a lateral section to estimate per stage oil and water contribution. Frac fluid was collected during completion and produced fluids were collected through the initial 189 days of production. A data science-based workflow was performed that tracked DNA markers within produced fluids and compared them to a well-cutting derived DNA baseline to estimate per-formation and per-stage contributions in the vertical and lateral sections, respectively. DNA Diagnostic results were integrated into a reservoir engineering workflow through comparisons with petrophysical logs, core data, geosteering reports, completions reports, production data, and oil tracers.
Results showed that initial drainage heights covered a large portion of the Barnett into Woodford formations and corresponded to the higher initial production values. Over time, the DNA drainage heights indicated a focused zone of contribution from the Barnett which corresponded to a steady, flat decline curve. Lateral DNA contributions estimates indicated the highest production contribution from a section of the lateral drilled within the intended landing zone towards the toe, which was corroborated with conventional oil-based chemical tracers. Additionally, the lateral DNA Stratigraphy plots allowed for the development of a hypothesis of a potential fault encountered in the lateral, which subsequent wells will investigate.
Overall, we demonstrate that Subsurface DNA Diagnostics provides an independent workflow to estimate drainage height and lateral production allocation by analyzing DNA markers acquired from cuttings and produced fluids. This work shows the complementary nature of incorporating DNA Diagnostics into traditional reservoir engineering workflows as a hypothesis generating tool and as a corroborative measurement. The scalability and non-invasive nature of the workflow has the potential to improve initial characterization and operations during field development, particularly exploratory areas with less operational history. DNA Diagnostics provided direct economic benefit to Novo's field development plan and informed subsequent capital allocation strategies.
In conventional reservoirs and certain tight reservoirs, both native reservoir quality and commodity pricing (via well economics) influence optimal well spacing outcomes. Optimized well spacing decisions in these reservoirs typically require case by case reservoir simulation studies and/or field trials both of which may be time consuming and impractical in the fast-paced unconventional reservoir development environment. In this paper, parametric reservoir simulation indicates that in reservoirs with formation diffusivity of less than 100,000 md-psi/cp commodity pricing and intrinsic reservoir properties have minimal effect on optimal well spacing. In these cases which include many shale reservoirs, the effective fracture half-length (Xf) is the singular determinant of optimum well spacing with NPV as the objective function. In these low diffusivity systems, well spacing optimization reduces to a geometric problem requiring predictive controls on effective fracture half-length. Classic rate/pressure transient techniques (RTA/PTA) are primarily diagnostic rather than predictive tools. Additionally, typical completions modelling tools are known to result in estimates of propped half-length which can be at variance with the effective fracture half-length (Barree et al. 2005, Rahim et al. 2012). This paper presents a predictive rate transient analytics (RTAN) framework within which the stimulated reservoir volume (SRV) quality and effective fracture half-length can be characterized as a function of 3D normalized treatment volumes (3DV) towards improved predictive controls on effective fracture half-length. Optimal prediction formalism is also introduced as a method to improve the predictive capacity of the 3DV parameter by accounting for geological and PVT variations. The combination of analytical well spacing modelling with rate transient analytics results in a data driven, integrated well spacing optimization workflow with reduced analysis time while preserving mechanistic integrity. Field applications in the Anadarko Woodford shale and Permian Wolfcamp are presented.
The low permeability of tight reservoir systems such as shales ensures that in many cases the long-term drainage area is limited to the stimulated reservoir volume (SRV). The well density/spacing is therefore a critical parameter in optimal field development planning especially in terms of recovery and field NPV maximization. In general, optimized well spacing decision requires case by case reservoir simulation studies and/or field trials which account for varying reservoir properties and economic conditions. Lalehrokh and Bouma (2014) apply a reservoir simulation-based workflow in the Eagle Ford shale to provide well spacing guidance in the black oil and condensate windows. The study indicates that a well spacing of 330 ft and 400 ft maximizes the NPV of a black oil Eagle Ford. The study assumes an effective fracture half-length of 100 to 150 ft obtained from rate transient analysis but does not address predictive controls on the assumed effective fracture half-lengths. Xiong and Wu (2018) recognize albeit without explicit proof, the effective fracture half-length as the key driver of optimal well spacing. They therefore employ an integrated multi-stage fracture modelling approach to predict effective fracture half-lengths. The workflow implements discrete fracture networks (DFN), completions and production history matching and simulation. Although the workflow provides extensive mechanistic grounding, the time required to execute a single well study may prove impractical in the fast-paced unconventional reservoir development environment. Additionally, Xiong and Wu (2018) refer extensively to the hydraulic and propped half-lengths whereas it is the effective fracture half-length that is of interest in production and well spacing optimization problems. As illustrated in figure 1, Barree et al. (2005), Rahim et al. (2012) show that typical completions modelling based on completions history matching may result in estimates of propped half-length which can be at variance with the effective fracture half length.