With the advent of high-resolution methods to predict hydraulic fracture geometry and subsequent production forecasting, characterization of productive shale volume and evaluating completion design economics through science-based forward modeling becomes possible. However, operationalizing a simulation-based workflow to optimize design to keep up with the field operation schedule remains the biggest challenge owing to the slow model-to-design turnaround cycle. The objective of this project is to apply the ensemble learning-based model concept to this issue and, for the purpose of completion design, we summarize the numerical-model-centric unconventional workflow as a process that ultimately models production from a well pad (of multiple horizontal laterals) as a function of completion design parameters. After the development and validation and analysis of the surrogate model is completed, the model can be used in the predictive mode to respond to the "what if" questions that are raised by the reservoir/completion management team.
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.
Since late 2017, more operators were started to drill new wells and the number of infills have been increased in the Haynesville Shale. However, as the infill wells are drilled between pre-existing wells (known as "parent well"), the impact of pressure depletion caused by adjacent existing producers may have a larger role in the performance of these new infill wells. And, how the various well spacing impact with the degree of reservoir pressure depletion from parent well is more important than ever for operators to optimize the completion design. This paper studies, in detail, how the change of the well spacing and reservoir depletion in the Haynesville will impact the new infill wells performance through modeling.
A real reservoir dataset was used to build a hydraulic fracture model and reservoir simulation model for parent wells in the Haynesville through fracture calibration and production history matching. The model was then used to evaluate the impact of production depletion on the stress reorientation and changes of stress magnitude through a coupled boundary element and finite element model through a geomechanics simulator. Three different production depletion times were modeled through the simulation, 0.5 years, 1 years and 3 years to understand the timing impact on the infill well production. Once the stress is updated for each case, a child well pad was added to the model next to the parent well and the well spacing to the parent well, various stimulation job sizes (small treatments versus large treatments), different pumping fluid rate for child well were simulated and evaluated to understand its impact on the created complex fracture propagation and total system recovery.
In this study, more than 200 different scenarios were simulated by using the cloud computation and each parameter was compared for different spacing senario among 3 different depletion times. This study can help us understand how the well spacing, completion job design and reservoir depletion impact the infill wells performance for two wells pad and help us optimize the infill well completion strategy in order to keep good production performance for new infill wells and avoid communication or fracture hit to the pre-existing wells in the Haynesville.
Green, Larrez (MDC Texas Energy) | Entzminger, David (MDC Texas Energy) | Tovar, David (MDC Texas Energy) | Alimahomed, Adnan (MDC Texas Energy) | Alimahomed, Farhan (Schlumberger) | Defeu, Cyrille (Schlumberger) | Malpani, Raj (Schlumberger)
Historically, vertical wells were used to correlate formation tops and determine the lateral continuity of the reservoir. With the advancements in horizontal drilling and logging, the industry is able to gather an immense amount of information about the rock as we drill farther away from the vertical section. Numerous industry publications indicate that approximately 40% of the perforation clusters in hydraulic fracturing do not contribute to production. Many factors play a role in such production behavior, but the most important factor is the breakdown of perforations and propagation of the hydraulic fractures through them. Several methods, such as limited entry design and placing perforations in similar type rock, have been applied to mitigate this problem; the information needed for these methods is obtained from logging the laterals or using drilling data to determine rock properties. Diagnostic tools such as production logs, permanent downhole fiber optics, radioactive tracers, and chemical tracers have been deployed to understand the varying production profiles seen across the unconventional reservoirs.
This study focuses on three wells with lateral measurements to obtain petrophysical and geomechanical rock properties (one well in the Wolfcamp B and two wells in the Wolfcamp A). The wells also had pseudo rock properties calculated using surface drilling data. In most instances, the perforation clusters in each stage were placed in good reservoir and completion quality rock with the aim to minimize the stress differential between clusters. Different perforation schemes were tested in each of the three wells - number of clusters and spacing, limited entry, and geometric design. The wellbore geosteering profile, whether in or out of zone, was also considered in relation to the subsurface structure.
Lateral measurements in all wells showed the changing lithology and rock types across the lateral. The Wolfcamp B had a production log that indicated twice as many clusters contributing in the section of engineered perforations compared to the section where the perforations were placed using the gamma ray log. Time-lapse chemical tracers in other wells indicated changing production profiles. For example, early in the life of a Wolfcamp A well, the stages with clusters picked based on logs showed the highest production contribution compared to the geometric stages, but, later, the trend started to shift in favor of the geometric clusters. The geometric stages were in an area of the wellbore where the carbonate content was highest.
Comparisons of various data sets to production performance, such as the one included in this study, will provide some insight into the heterogeneous nature of the Wolfcamp shale and the impact of varying perforation techniques on production contribution from individual clusters.
Xu, Tao (Schlumberger) | Lindsay, Garrett (Schlumberger) | Zheng, Wei (Schlumberger) | Yan, Qiyan (Schlumberger) | Escobar Patron, Katherine (Schlumberger) | Alimahomed, Farhan (Schlumberger) | Panjaitan, Maraden Luigie (Schlumberger) | Malpani, Raj (Schlumberger)
Since early 2016, commodity prices have been gradually increasing, and the Permian Basin has become the most active basin for unconventional horizontal well development. As the plays in the basin are developed, new infill wells are drilled near pre-existing wells (known as "parent wells"). The impact of pressure depletion caused by adjacent existing producers may have a larger role in the performance of these new infill wells. How the various well spacing impact with the degree of reservoir pressure depletion from parent well is more important than ever for operators to optimize the completion design. Through data analytics and comprehensive fracture/reservoir modeling this paper studies how changes in well spacing and proppant volume in the Spraberry, a main formation in the Permian Basin, will impact new infill well performance. The studies in this paper are focused on the Midland Basin.
A public database was used to identify the number of parent and child wells in the Midland basin. Data analysis of production normalized by total proppant and lateral length shows that parent wells outperform infill, or child, wells. To further understand the relationship between parent and child wells, a reservoir dataset for the Spraberry formation was used to build a hydraulic fracture and reservoir simulation model for both the parent well and a two-well infill pad. After production history matching a P50 type well as the parent well, three periods of production depletion were modeled (6 months, 3 years and 5 years) to understand the timing impact on the infill well production. A geomechanical finite-element model (FEM) was then used to quantify the changes to the magnitude and azimuth of the in-situ stresses from the various reservoir depletion scenarios. A two-well infill pad was then simulated into the altered stress field next to the parent well at various spacings between the parent and child wells. A sensitivity was then performed with different stimulation job sizes to understand the volume impact on created complex fracture propagation and total system recovery.
This study can help operators understand how well spacing, reservoir depletion, and completion job size impact the infill well performance so they can optimize their infill well completion strategy.
During the downturn in the oil and gas industry, many operators have chosen to refracture their previously underperforming wells to boost economics with lower investment compared to drilling new wells. More than 100 horizontal wells have been refractured using chemical diverters across multiple basins in North America since the second half of 2013. Many papers have been published discussing these case studies. However, the refracturing results have been inconsistent. One of the biggest challenges of refracturing with chemical diverters is not knowing what is actually happening down hole. To better understand what is happening, more refracture modeling should be performed to more reliably predict production results before spending the upfront capital for a refracturing treatment.
A proposed refracture numerical simulation methodology was employed to take into account the historical production depletion using calculated pressure and stress measurements along the lateral and in the reservoir. The altered stress fields resulting from reservoir depletion are calculated through a comprehensive workflow coupling simulated 3D reservoir pressure with a geomechanical finite-element model (FEM) described in a previous published paper. After the stress and pressure are updated, the new approach outlined in this paper is validated by production history matching real data from a previously refractured well in the Haynesville basin to provide more confidence in the end results. The main uncertainty in the process is how much of the lateral was stimulated. This paper also provides a sensitivity example to show how the model can be altered to predict different lateral coverage percentages.
Refracture modeling still poses a major challenge for engineers because of the reservoir complexity and uncertainty downhole while refracturing (i.e. reservoir heterogeneity, isolation efficiency, etc.). However, this proposed refracturing approach provides a basic guideline on how to model refracturing treatments in a numerical simulator with the help of altered stress fields caused by reservoir depletion. This can be used to better understand why previously refractured wells perform the way they do and to better predict the performance of future refractured wells.
The Midland Basin has seen an unprecedented boom in pad drilling over the last year, largely due to the stacked pay, comprising of the Spraberry and the Wolfcamp formations. Operators are targeting up to four different reservoirs in one section, using a wine-rack pattern, which is the future of pad drilling. The workflows discussed in this paper will help us in understanding the growth of the hydraulic fractures and their production interference with the offset wells. These integrated workflows are centered on building a calibrated 3D model, to perform predictive modeling on various combinations of stacked laterals and determine the optimum spacing, both vertically and laterally.
Technology integration plays a significant role in identifying the key drivers of production. Our workflows involve building a geomodel using high tier pilot well logs and utilizing an unconventional fracture model (UFM) to simulate hydraulic fractures to understand the overall fracture footprint. The fractures are then gridded in an unstructured manner and fed to a numerical reservoir simulator to perform production history matching. This is the most crucial step in the process because this calibrated model is then usedfor predictive modeling of the various combinations of lateral spacing and stacking.
Pilot well logs show varying degrees of high stress barriers that exist across the basin, and knowing the stress regime local to a field or section is important in determining the optimum landing locations and completion designs. Typical pump schedules for the zones of interest were selected based on current industry practices. Fully 3D planar fracture simulations performed on the pilot well resulted in 18 potential landing locations spanning the Upper Spraberry to the Lower Cline, based on fracture heights and theinterference between the zones. Out of the 18 targets, fivewere selected based on production potential. UFM simulations along the lateral show different fracture geometries in different reservoirs due to varying rock properties and natural fracture orientations. The production history matching was performed using a P50 type curve generated using public data for eachreservoir in the county, and using known reservoir fluid properties.
The modeling approach discussed in this paper can be applied to any data set within the basin to determine the optimum landing location, which could vary depending on changing reservoir properties. It acts as an alternative approach to field testing varying spacing combinations, which could be both, expensive and time consuming.
As commodity prices have declined, refracturing has given operators an alternative way to obtain positive returns with lower investment under constrained capital markets. A major operator in the Haynesville shale was interested in determining the optimum method to refracture several laterals located directly offset to each other. In this case, a four-well pad was initially drilled to drain the section. The viability and optimum sequence/design of refracturing this four-well pad was unknown. There were many uncertainties around refracturing this pad including refracturing approach/method, refracture timing, refracture sequence (well order), refracture job size, and number of wells to refracture to obtain the greatest return on investment.
In this paper, an integrated refracturing workflow was created and applied to determine the optimum refracturing strategy for this four-well pad. This comprehensive workflow represents a multidisciplinary approach that integrates complex hydraulic fracture models, geomechanical models, and multiwell production simulation. The unique approach in this workflow was the ability to couple simulated 3D reservoir pressure with a geomechanical finite-element model (FEM) to quantify the changes to the magnitude and azimuth of the in-situ stresses from the depletion. Then, the altered stress field was utilized as the input for modeling the new fracture system created by the refracturing treatment. A separate refracturing workflow was developed to calibrate the proposed four-well refracture study by fracture modeling and production history matching of a previously refractured well a few miles away, and it was also applied to run sensitivities on modeling the proposed refracture treatments on the four-well pad.
This new unique approach to studying pad refracturing was beneficial to understanding the viability of refracturing this four-well pad in the Haynesville shale and the influence of refracturing on the existing fracture networks. The optimized completion strategy and workflow can help operators calibrate expectations and optimize the refracturing process for pad wells to obtain the best return on investment.
The Haynesville shale is a unique dry gas formation located in northeast Texas/northwest Louisiana with high reservoir pressure, gradients of 0.85 to 0.9 psi/ft (Fan et al. 2010; Thompson et al. 2010). The higher reservoir pressure and clay content cause the play to be prone to creep, which causes severe permeability reduction as wells are produced with high drawdowns (Thompson et al. 2010; Okouma Mangha et al. 2011; Indras and Blankenship 2015). By controlling the severe production drawdown, existing fracture networks were maintained for longer periods of time (Baihly et al. 2015).
Production drivers including reservoir, completion quality, and number and quality of hydraulic fracture stages influence overall production performance of a well. In an integrated engineering study, all production drivers were assumed to be very similar except for the well horizontal lateral length. Well production rate was calculated with horizontal lateral lengths varying from about 1,000 ft to 20,000 ft with an increment of 1,200 ft. Statistical field data and integrated reservoir-wellbore simulation were compared to draw a comprehensive conclusion. Different domain engineering principles were used to understand the impact of increase in lateral length on production performance of horizontal shale wells.
Gakhar, Kush (Schlumberger) | Rodionov, Yuri (Schlumberger) | Defeu, Cyrille (Schlumberger) | Shan, Dan (Schlumberger) | Malpani, Raj (Schlumberger) | Ejofodomi, Efe (Schlumberger) | Fischer, Karsten (Schlumberger) | Hardy, Barry (Marathon Oil)
As the oil & gas industry enters into next phase of unconventional reservoir development, many new in-fill wells will be drilled in various shale oil and gas plays in North America. A detailed evaluation to devise an engineered approach for stimulating and completing these wells is critical to maximizing productivity. Challenging economics that prevail today have made it even more vital to perform such a study. This paper focuses on identifying optimum stimulation treatment design and completions strategy for the in-fill well. This work is a companion work to a paper presented by
An ‘advanced integrated modeling workflow’ is used to execute the complex study. The workflow involves building a 3D structural geologic model based on a vertical openhole pilot well log in Eagle Ford shale reservoir. A discrete fracture network (DFN) is built from 3D seismic data interpretation. Hydraulic fracture treatment pumped on a parent well is simulated using ‘unconventional fracture model’ (UFM). The UFM simulates complex fractures, while honoring the interaction between hydraulic fractures and natural fractures. A dynamic grid with unstructured cells is then created. Hydrocarbon production from the parent well is simulated for a period of 400 days. A geomechanical finite element model (FEM) based simulator that is fully coupled with a 3D numerical reservoir simulator is then used to calculate spatial and temporal changes in in-situ stresses. Dynamic reservoir properties in the 3D model are then updated and the child well, which is drilled 600 ft away from the parent well, is built into the model. The UFM is used to simulate an array of stimulation treatment designs and compare alternate completions strategies for the child well. The reservoir simulator is then used to compare production performance of the alternate strategies. Note that in this paper, the terms "in-fill well" and "child well" are used interchangeably.
Extensive evaluation is carried out using the advanced integrated modeling workflow to achieve three key objectives. The first key objective is to determine an appropriate hydraulic fracturing treatment design for an in-fill well. Four hydraulic fracture treatment designs based on slickwater, delayed borate crosslinked gels, hybrid fluid treatments, and fiber based channel fracturing fluids for the in-fill well are compared. It has been found that under reservoir conditions specific to this study, the child well produces 22% more oil, if stimulated using the fiber based channel fracturing fluid than, if fractured using the slickwater. The second key objective is to compare the impact of refracturing and recharging the parent well prior to fracturing the child well. For the study well, refracturing increases oil production from the multi-well pad by 11% over the scenario, in which the parent well is recharged by injecting 43,200 bbl of water. The third objective of this study pertains to comparing the traditional plug-and-perf completions design with an alternate based on coupling plug-and-perf with a novel "sequenced fracturing" technique with a degradable fiber based fluid diversion blend for the child well. It has been found that by using the latest sequenced fracturing technique oil production from the multi-well pad can be increased by 14% over a scenario in which the child well is completed using traditional plug-and-perf design, despite pumping fewer stages on the well. The novel completion technique also greatly improves the efficiency of operation and provides significant savings on completions cost.