Using planar fracture models to match treatment pressure and improve understanding of the fracture geometry generation is not a new concept. Knowledge gained from this exercise has historically been used to improve engineered fracture completions and production, and maximize net present value (NPV); however, at some point during the progression from vertical to horizontal wellbores, many within the industry have forgotten about the learnings that can still be gained from current fracture models. Engineered completions have been largely replaced by spreadsheet efficiencies relevant to operations rather than production in too many cases. Some images of unconventional well stimulation treatments portray fractures growing in every direction, forming patterns that resemble shattered windshields, and have often excluded the known physics related to rock geomechanics, reservoir properties, and geology. Excuses to dismiss modeling are numerous and are gaining the reasoning of conformists.
Unconventional resource plays might or might not contain large numbers of natural fractures; but, current fracture models can still be used to gain insight into the fracture geometries being generated. While the development of complex fracture models continues to evolve, the industry can still gain insight to fracture geometry and resulting production using current planar fracture modeling. Caveats to this process are that it requires: Valid measured data to establish model constraints. The engineer to understand the basic physics of how fractures are generated and when (and when not) to twist the "knobs" in the model. The engineer to understand which "knobs" should be used based on real diagnostics information. The actual single well production to be an integral part of the process.
Valid measured data to establish model constraints.
The engineer to understand the basic physics of how fractures are generated and when (and when not) to twist the "knobs" in the model.
The engineer to understand which "knobs" should be used based on real diagnostics information.
The actual single well production to be an integral part of the process.
This paper demonstrates the results of honoring data measurements from a multitude of potential sources, including downhole microseismic data, downhole deformation tiltmeters, offset pressure monitoring, DTS, DAS, diagnostic fracture injection test (DFIT) analysis, injection as well as production data with bottomhole pressure measurements, etc., and the resulting observations and conclusions. Several industry examples are discussed to help frame the vast amount of information possible to help engineers do a better job of including more diagnostics into routine operations to provide additional insight and ultimately result in improved models and completion designs.
This paper is not intended to merely demonstrate the results of the work but to spark an interest in bringing more intense engineering back to fracture stimulation modeling for horizontal completions.
Inyang, Ubong (Halliburton) | Cortez-Montalvo, Janette (Halliburton) | Dusterhoft, Ron (Halliburton) | Apostolopoulou, Maria (University College London) | Striolo, Alberto (University College London) | Stamatakis, Michail (University College London)
Estimating the effective permeability and microfracture (MF) conductivity for unconventional reservoirs can be challenging; however, a new method for estimating using a stochastic approach is discussed. This new analysis method estimates matrix permeability and the unpropped and propped MF conductivities during laboratory testing where MFs were propped with ultrafine particles (UFPs).
Kinetic Monte Carlo (KMC) simulations form the basis of the method used to estimate effective permeability of the core sample. First, the stochastic model was implemented to calculate effective matrix permeability of a small core taken from unfractured Eagle Ford and Marcellus formation samples using scanning electron microscopy (SEM) images and adsorption data to obtain the pore-size distribution (PSD) within the sample. The KMC approach then evaluated the effect of various parameters influencing the conductivity of laboratory-created MFs. Case studies considered for this work investigate the conductivity improvement of a manmade MF as a function of the UFPs used as proppants that maintain width under high stress, the UFP (proppant) concentration, and the UFP flow perpendicular into a secondary or adjacent MF zone (2ndMF) penetrating the face of an opened MF during flow testing under stress. The leakoff area widths considered were 1, 2, and 3 mm and can be propped or unpropped.
Results obtained for the unfractured Eagle Ford and Marcellus samples closely correlate with other computational and experimental data available. For the laboratory-prepared nonpropped and propped MF samples, the effective propped width was determined to have the greatest effect on the MF conductivity, which increased by two orders of magnitude in the presence of the UFPs. The remaining two factors—proppant concentration and length of 2ndMFs—helped improve the effective MF conductivity in a linear manner; the highest proppant concentration and the 2ndMF zone resulted in the highest fracture conductivity achieved. Insight obtained from this study can be used to optimize fracturing designs by including UFPs and to create strategies for maximizing hydrocarbon recovery during development of unconventional resources where MFs are opened during stimulation treatments.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Most current hydraulic fracturing operations are performed in unconventional reservoirs (i.e., tight gas and oil reservoirs and organic-rich shale plays) that have sub-microdarcy permeability and require stimulation to achieve commercial flow. Hydraulic fracturing helps unlock these reservoirs by creating a fracture network to access the resources.
This paper describes the stress-dependent permeability of split shale core plugs from Eagle Ford, Bakken, and Barnett formation samples studied in presence of microproppants in microcracks. An analytical permeability model is developed, including the interaction between the fracture walls and monolayer microproppants under stress. The model is then used to analyze a series of pressure pulse decay measurements of the propped shale samples in the laboratory. The analysis provides the propped fracture permeability of the samples and predicts a parameter related to the quality of the proppant areal distribution in the fracture. The proppant placement quality can be used as a measure of success of the delivery of proppants into the fractures and to design stimulation in the laboratory.
Because commodity prices have substantially decreased since peaking in late 2014, operators have implemented strategies that focus on the most prolific acreage and have concentrated drilling activities on the "sweet spots" in many unconventional plays. This development practice has resulted in decreased well spacing and infill (development) wells being drilled in close proximity to parent (delineation) wells, causing lower productivity than expected in many development wells because of drainage area and fracture interference. Many operators use a method known as parent well protection (PWP) to help mitigate this effect and increase recovery from both parent (delineation) and closely offsetting development (child) wells. This paper presents an analysis of the economic impact of PWP treatments performed for repressurizing the reservoir system and chemical stimulation of the parent well.
This evaluation of PWP production benefits was performed using a combination of numerical reservoir simulation with advanced gridding and reservoir modeling capabilities and economic analysis tools for net present value (NPV) evaluation. Advanced modeling capabilities helped enable grid transformation of the simulation grid at the time of completion of the infill well to simulate the effects of drainage area interference. Wellbore flow parameter alterations modeling near-wellbore (NWB) and skin damage effects were implemented. In addition to fracture interference mitigation, NWB damage remediation of the parent well was implemented at varying magnitudes to simulate the effects of a chemical stimulation treatment performed in conjunction with the repressurization treatment. An analysis of the fiscal impact of the PWP treatment with water only and PWP treatment with stimulation fluids was performed to determine the scenario with optimal NPV.
Results indicated that substantial benefit can be realized through PWP treatments. The primary goal of the PWP treatment is to help prevent production loss in the parent well and mitigate production interference from the child well completion. Production interference is caused by asymmetric fracture growth from the child well completions into the depleted region around the parent well (typically the area of least stress). Simulation results showed that mitigation of asymmetric fracture growth can result in an increase in 4-year cumulative recovery of up to 21%. Chemical stimulation treatments addressing only NWB/skin damage can result in an increase in 4-year cumulative recovery of up to 16%. Combining both resulted in an increase of up to 36%. The break-even price for the cost of the PWP treatment, rate of return (ROR), and return on investment (ROI) were evaluated and associated with the cumulative production of the various reservoir models. This paper presents case histories and examples of PWP treatments.
The benefits of PWP treatments cannot only be evaluated based on the incremental recovery in the parent well, but should also take into account production loss from fracture interference in both the parent and child wells. Increased recovery and economics can be achieved through stimulation of the parent well in conjunction with repressurizing, prior to completion of the child well.
This paper presents a new workflow that combines the stochastic earth model and geomechanical analysis to assess the best geological landing intervals and geomechanical targeting zones in unconventional reservoirs before drilling and completion operations. The stochastic earth model uses geostatistical algorithms and multivariate analytics to create a shale quality index (QI) that identifies potential zones with a high probability of containing organic-rich, brittle shales with low effective shale water saturation. The geomechanical analysis uses the material point method (MPM) solid mechanics tools to assess the stress field in the fractured reservoir. This helps identify the best zones for hydraulic fracturing operations that can enable the development of a complex stimulated reservoir volume. The value of combining the two methods is illustrated in two generic areas (Areas A and B). Both areas have the same high shale QI but have different fracture sets characteristics. Area A has a broad range of fractures orientation and Area B has a uniform orientation. A sensitivity analysis highlighted the importance of shear fractures for deriving stress variability. Fractures oriented along and perpendicular to the maximum horizontal stress showed less impact. However, the final stress field was driven by the interaction between different fractures sets, when present. Geomechanical analysis of Area A indicated many zones of low-to-medium differential stress (DS) within high QI zones. However, Area B had a zone of high DS. Area A had a broader range of fracture orientation, which could result in more stress variability and possible connectivity of the induced fractures to the reservoir. These observations could affect the production of wells in similar areas. Therefore, the combined geomechanical and earth model analysis workflow is important to better understand shale reservoirs and adapt stimulation treatments according to local stress conditions related to the reservoir geology and geomechanics sweet spots. Thus, the integrated shale QI and geomechanical analysis can be used to design a fracturing operations strategy for wells to determine target stages.
The current low commodity prices present numerous challenges in the oil and gas industry, particularly in the unconventional reservoirs that have experienced tremendous growth in the past decade and still hold significant untapped potential. The positive aspect of the current downturn is the recognition that current hydraulic fracturing practices do not meet expectations, thus initiating new industry-wide efforts to optimize drilling and completion strategies in unconventional reservoirs.
Horizontal wells in liquids-rich shale plays are now being drilled such that lateral and vertical distances between adjacent wells are significantly reduced. In multistacked reservoirs, fracture height and orientation from geomechanical effects coupled with natural fractures create additional complications; therefore, predicting well performance using numerical simulation becomes challenging. This paper describes numerical simulation results from a three-well pad in a stacked liquids-rich reservoir (containing gas condensates) to understand the interaction between wells and production behavior.
This paper discusses the use of an unstructured grid-based numerical simulator that incorporates complicated geometries of both hydraulic and natural fractures. It can handle compositional simulation to better model gas condensates with special focus on timing of third well placement and the loss of conductivity effects on production from these wells. A base case was created with a stacked shale play containing three parallel wells but with staggered elevations. Variables used in this study include matrix permeability, condensate-to-gas ratio (CGR), fracture length, well staggering, time of well placement, conductivity degradation, and presence of natural fractures. Simulation runs were conducted for a five-year duration.
More than 20 compositional simulation runs were conducted. For the base case, staggering resulted in a slight decrease in both cumulative oil and gas production compared to a case without staggering. Matrix permeability had the most dominant effect on both oil and gas production. Fracture and matrix conductivity losses were more detrimental to cumulative gas production than oil production. For the limited cases studied, placement of the third well one year after the first two wells began producing resulted in a spike in both oil and gas production from the pad. This produced cumulative oil and gas amount was close to that of three wells producing simultaneously, especially if fracture half-lengths for the third well were the same as the first two. However, cumulative oil and gas production reduced significantly if fracture half-lengths were smaller than the other two wells. When all wells experienced significant conductivity loss, gas production was affected more than oil production when the third well was placed one year after the first two wells began producing. In all cases, placing the third well between the other wells was helpful in increasing overall production from this pad. Natural fractures increased both oil and gas production in the cases studied.
This paper addresses important issues associated with a liquids-rich unconventional play. It demonstrates successful use of unstructured grid-based reservoir simulation modeling to address well placement timing, well staggering, conductivity damage effects, natural fractures, hydraulic fractures not perpendicular to the wellbores, and several other important issues for which little is known so far. Results from this study type can be used to make important decisions regarding well placement and timing in a multiwell setting.
Dahl, Jeff (Devon Energy) | Calvin, James (Halliburton) | Siddiqui, Shameem (Halliburton) | Nguyen, Philip (Halliburton) | Dusterhoft, Ron (Halliburton) | Holderby, Eric (Halliburton) | Johnson, Bill (Halliburton)
This paper discusses a study of condensate-rich Barnett Shale stimulation treatments with designs incorporating a micro-proppant (MP). By placing this proppant early during treatment, it can enter into the narrow natural fracture network where proppant even as small as 100 mesh cannot access. A description of the MP, area regional formation and fracture modeling, stimulation designs, reservoir simulation production results, and production comparisons to offsets are presented.
In present day shale plays, maximizing communication between natural fracture systems and the wellbore while also avoiding any damage to those natural fractures are two pillars of optimized stimulation. Increased proppant volume in primary fractures and helping ensure the near-wellbore (NWB) area of these fractures is open are two important stimulation concepts. Further improvements depend on:
Communicating with a greater number of natural fractures. Enhancing the number of secondary fractures opened. Increasing the number of these secondary fractures that remain open for the long term.
Communicating with a greater number of natural fractures.
Enhancing the number of secondary fractures opened.
Increasing the number of these secondary fractures that remain open for the long term.
Of these three items listed, the third is probably the most challenging. This paper presents a study of MP use with the goal of propping natural fractures in a liquids-rich area of the Barnett, wherein the first and second items listed have already been addressed and provided significant production improvement. A well-to-well comparison of MP use revealed another step-change in an otherwise optimized drilling and completion program. Production history matching using advanced discrete fracture network (DFN) simulations of hydraulic fractures with the complexity of natural fractures included helped provide insight into how relatively small conductivity improvement to the natural fractures significantly improved well productivity. A new complex fracture design simulator successfully predicted the most favorable method within the fracturing design to include a MP entering these narrow natural fractures and thus improving conductivity. With the understanding gained from these new modeling tools, the MP was then field tested and proven to enhance production response.
Dahl, Jeff (Devon Energy) | Samaripa, James (Devon Energy) | Spaid, John (Devon Energy) | Hutto, Erek (Halliburton) | Johnson, Bill (Halliburton) | Buller, Dan (Halliburton) | Dusterhoft, Ron (Halliburton)
Past standard stimulation treatments for the Eagle Ford formation in South Texas have consisted of 200-ft stages, six clusters per stage, and 1,500 to 1,750 lbm of proppant per foot of lateral with ramps of 40/70- to 30/50-mesh proppant. Typical laterals consist of 25 to 30 stages, which contributes significantly to the well's completion budget. In Lavaca County, attempts were made to reduce the cost per barrel of oil equivalent (BOE) and improve the estimated ultimate recovery (EUR) using better fracture placement, as determined with a log-derived completion software to select perforation clusters and stage locations.
Three wells were evaluated for this study. Well A was drilled in January 2014 toe-down and stimulated similar to a standard stimulation using 25 stages. Well B is a direct offset to Well A. Pilot-hole logs and gamma ray logging- while-drilling (GRLWD) data were available for Well B, which was drilled toe-up. The original completion and lateral length was designed for a 31-stage completion. Using the vertical open hole and logging-while-drilling (LWD) log data combined with the completion software, a 19-stage stimulation was designed and executed. Well A and Well B had the same average pay thickness over the lateral. Well C was drilled from the same pad as Well B but toe-down. GRLWD data were used for steering, and a cased-hole pulsed neutron log (PNL) was run in the lateral. Well C was drilled with the formation's net pay narrowing from a 30-ft thickness to less than 10 ft near the end. The software-optimized stimulation design used the correlated pulsed neutron evaluation and called for nine stages.
Production from Well B, completed with 19 stages, was essentially the same as for the 25-stage stimulation in Well A after 100 days. Increasing the stage length, using proper cluster placement, and reducing the number of stages required, the engineered approach used in Well B reduced stimulation costs by nearly 40%. Well A was re-evaluated using the completion optimization software to determine if the software would design the stimulation placement differently. Results from the analysis showed that the well could have been stimulated with half the number of stages.
The process uses a novel approach to compare reservoir quality and rock mechanical properties throughout a lateral, allowing for a designed cluster placement in like rock, a potential increase in cluster efficiency, and an optimum stage length, which results in significant cost savings.
As more wells are drilled and completed in tight, brittle formations, operators rely more on small-sized proppants to help ensure the created complex fractures are propped, and to maintain conductive flow paths for production. Most microfractures generated in the far-field away from the primary fracture branches are believed to return to a closed state soon after the release of hydraulic pressure, unless propping agent has been successfully placed inside such fractures. This paper presents the results of laboratory study, numerical modeling, and field trials, to demonstrate and quantify the effectiveness of a new treatment method for enhancing conductivity of microfractures and primary fractures formed in tight formations, thus helping improve well production.
The approach involves using a micro-proppant (MP) and an aqueous-based surface modification agent (ASMA) as part of the pad fluid stage to treat fracture faces of microfractures and leakoff induced fractures before placement of larger-sized proppant into the primary fractures. This coating causes the proppant particulates to adhere to the created fracture faces by forming partial monolayer, thus mitigating settling and enhancing vertical distribution in the fractures. During experimental testing, various shale core samples were split along the core length to create artificial fracture faces. These fracture faces were then exposed to MP or proppant slurry treated with an ASMA, and were then reassembled for core flow testing under closure stress. An effective permeability comparison of the fractured cores, with and without ASMA treated MP or proppant, demonstrated a dramatic effective permeability increase in fractures of the treated cores.
Field treatments involved injection of pad fluid containing a low concentration of MP, with and without treating with ASMA in offset wells, to treat the microfractures formed in the far-field regions. Proppant slurry of larger size particulates (100-mesh and larger) then followed to prop the primary fractures and their branches. Production from wells treated with MP have shown to provide significant improvement in terms of liquids production compared to the production of control wells. Reservoir simulation performed in this complex retrograde condensate reservoir supports this result, with sensitivity testing showing that increasing the connected fracture area enables the production of more hydrocarbon liquids at higher sustained production rates.