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Abstract There are mainly two types of solids in the oil field waters; Suspended Solids (SS) and Total Dissolved Solids (TDS). While it is easy to remove SS from water, removal of TDS requires the application of advance filtration techniques such as reverse osmosis or ultra-filtration. Because these techniques cannot handle high volumes of the oilfield waters with high TDS content, produced waters originated from hydraulic fracturing activities cannot be treated by using these advance technologies. Thus, in this study we concentrated on the pretreatment of these waters. We investigated the feasibility of the Coagulation, Flocculation, and Sedimentation (CFS) process as pretreatment method to reduce mainly SS in Produced Water (PW) samples. We collected samples from 14 different wells in the Permian Basin. First, we characterized the water samples in terms of pH, SS, TDS, Zeta potential (ZP), Turbidity, Organic matter presence and different Ion concentration. We tested varying doses of several organic and inorganic chemicals, and on treated water samples we measured pH, TDS, SS, Turbidity, ZP and Ions. Then, we compared obtained results with the initial PW characterizations to determine the best performing chemicals and their optimal dosage (OD) to remove contaminants effectively. The cation and anion analyses on the initial water samples showed that TDS is mainly caused by the dissolved sodium and chlorine ions. ZP results indicated that SS are mainly negatively charged particles with absolute values around 20 mV on average. Among the tested coagulants, the best SS reduction was achieved through the addition of ferric sulfate, which helped to reduce the SS around 86%. To further lessen SS, we tested several organic flocculants in which the reduction was improved slightly more. We concluded while high TDS in the Permian basin does not implement a substantial risk for the reduction of fracture conductivity, SS is posing a high risk. Our study showed, depending on components of the initial PW, reuse of the pretreated water for fracturing may minimize fracture conductivity damage.
Abstract The vast shale gas and tight oil reservoirs cannot be economically developed without multi-stage hydraulic fracture treatments. Owing to the disparity in the density of natural fractures and the different in-situ stress conditions in these formations, micro-seismic fracture mapping has shown that hydraulic fracture treatments develop a range of large-scale fracture networks. The effect of these various fracture geometries on production is a subject matter in question. The fracture networks approximated with micro-seismic mapping are integrated with a commercial numerical production simulator that discretely models different network structures. Two fracture geometries have been broadly proposed, i.e., orthogonal and transverse. The orthogonal pattern represents a network with cross-cutting fractures orthogonal to each other, whereas transverse profile maps uninterrupted fractures achieving maximum depth of penetration into the reservoir. The response for a single stage is further investigated by comparing the propagation of each stage to be dendritic versus planar. A dendritic propagation is a bifurcation of the induced hydraulic fracture due to the intersection with the natural fracture (failure along the plane of weakness). For the same injected fracture treatment volume, the transverse network attains a higher penetration into the reservoir, achieves a higher stimulated reservoir volume (SRV), and produces around 40-65% more than the orthogonal network over a timespan of 10 years. The SRV will largely dictate the drainage area in a tight environment. The cumulative production rises until the pressure drawdown reaches the extent of the fracture fairway. For the orthogonal network, the unstimulated reservoir boundary is reached at a sooner time than the transverse network. It is found that by increasing the fracture spacing in both the networks from 100 ft to 150 ft, the relative production was enhanced in the orthogonal network by 41%, but when it was further increased to 200 ft- there was a minor drop (not increase) in the relative production (4.5%). For an infinite conductivity fracture, the width of the fracture has minimal effect on oil and gas production. For the dendritic pattern, the size of the SRV created due to the interaction between the induced and natural fractures largely depends on the length of natural fractures and the point of interaction (center, off-center, or extremity). Effect of length, distance of natural fracture from wellbore, and the point of interaction is evaluated. A novel approach for reservoir simulation is used, where porosity (instead of permeability) is used as a scaling parameter for the fracture width. The forward modeling effort, including the comparative fracture geometries setup, induced, and natural fracture interaction parametric study, is unique.
Zhou, Peng (Department of Petroleum Engineering, Texas A&M University, College Station, TX, United States) | Lu, Ligang (Shell International Exploration and Production Inc, Houston, TX, United States) | Sang, Huiyan (Department of Statistics, Texas A&M University, College Station, TX, United States) | Dindoruk, Birol (Department of Petroleum Engineering, University of Houston, TX (formaly with Shell International Exploration and Production Inc, Houston, TX), United States)
Abstract In unconventional reservoirs, optimal completion controls are essential to improving well productivity and reducing costs. In this article, we propose a statistical model to investigate associations between shale oil production and completion parameters (e.g., completion lateral length, total proppant, number of hydraulic fracturing stages), while accounting for the influence of spatially heterogeneous geological conditions on hydrocarbon production. We develop a non-parametric regression method that combines a generalized additive model with a fused LASSO regularization for geological homogeneity pursuit. We present an alternating augmented Lagrangian method for model parameter estimations. The novelty and advantages of our method over the published ones are a) it can control or remove the heterogeneous non-completion effects; 2) it can account for and analyze the interactions among the completion parameters. We apply our method to the analysis of a real case from a Permian Basin US onshore field and show how our model can account for the interaction between the completion parameters. Our results provide key findings on how completion parameters affect oil production in that can lead to optimal well completion designs.
Pei, Yanli (University of Texas at Austin (Corresponding author) | Yu, Wei (email: firstname.lastname@example.org)) | Sepehrnoori, Kamy (University of Texas at Austin and Sim Tech LLC) | Gong, Yiwen (University of Texas at Austin) | Xie, Hongbing (Sim Tech LLC and Ohio State University) | Wu, Kan (Sim Tech LLC)
Summary The extensive depletion of the development target triggers the demand for infill drilling in the upside target of multilayer unconventional reservoirs. However, such an infill scheme in the field practice still heavily relies on empirical knowledge or pressure responses, and the geomechanics consequences have not been fully understood. An embedded discrete fracture model (EDFM) is deployed in our fluid-flow simulation to characterize complex fractures, and the stress-dependent matrix permeability and fracture conductivity are included through the compaction/dilation option. After calibrating reservoir and fracture properties by history matching of an actual well in the development target (i.e., third Bone Spring), we run the finite element method (FEM)-based geomechanics simulation to model the 3D stress state evolution. Then a displacement discontinuity method (DDM) hydraulic fracture model is applied to simulate the multicluster fracture propagation under an updated heterogeneous stress field in the upside target (i.e., second Bone Spring). Numerical results indicate that stress field redistribution associated with parent-well production indeed vertically propagates to the upside target. The extent of stress reorientation at the infill location mainly depends on the parent-child horizontal offset, whereas the stress depletion is under the combined impact of horizontal offset, vertical offset, and infill time. A smaller parent-child horizontal offset aggravates the overlap of the stimulated reservoir volume (SRV), resulting in more substantial interwell interference and less desirable oil and gas production. The same trend is observed by varying the parent-child vertical offset. Moreover, the efficacy of an infill operation at an earlier time is less affected by parent-well depletion because of the less-disturbed stress state. The candidate infill-well locations at various infill timings are suggested based on the parent-well and child-well production cosimulation. The conclusions provide practical guidelines for the subsequent development in the Permian Basin.
Summary Stimulated reservoir volume (SRV) is a prime factor controlling well performance in unconventional shale plays. In general, SRV describes the extent of connected conductive fracture networks within the formation. Being a pre-existing weak interface, natural fractures (NFs) are the preferred failure paths. Therefore, the interaction of hydraulic fractures (HFs) and NFs is fundamental to fracture growth in a formation. Field observations of induced fracture systems have suggested complex failure zones occurring in the vicinity of HFs, which makes characterizing the SRV a significant challenge. Thus, this work uses a broad range of subsurface conditions to investigate the near-tip processes and to rank their influences on HF-NF interaction. In this study, a 2D analytical workflow is presented that delineates the potential slip zone (PSZ) induced by a HF. The explicit description of failure modes in the near-tip region explains possible mechanisms of fracture complexity observed in the field. The parametric analysis shows varying influences of HF-NF relative angle, stress state, net pressure, frictional coefficient, and HF length to the NF slip. This work analytically proves that an NF at a 30 ± 5° relative angle to an HF has the highest potential to be reactivated, which dominantly depends on the frictional coefficient of the interface. The spatial extension of the PSZ normal to the HF converges as the fracture propagates away and exhibits asymmetry depending on the relative angle. Then a machine-learning (ML) model [random forest (RF) regression] is built to replicate the physics-based model and statistically investigate parametric influences on NF slips. The ML model finds statistical significance of the predicting features in the order of relative angle between HF and NF, fracture gradient, frictional coefficient of the NF, overpressure index, stress differential, formation depth, and net pressure. The ML result is compared with sensitivity analysis and provides a new perspective on HF-NF interaction using statistical measures. The importance of formation depth on HF-NF interaction is stressed in both the physics-based and data-driven models, thus providing insight for field development of stacked resource plays. The proposed concept of PSZ can be used to measure and compare the intensity of HF-NF interactions at various geological settings.
Summary We propose a novel method for estimating average fracture compressibility during flowback process and apply it to flowback data from 10 multifractured horizontal wells completed in Woodford (WF) and Meramec (MM) formations. We conduct complementary diagnostic flow-regime analyses and calculate by combining a flowing-material-balance (FMB) equation with pressure-normalized-rate (PNR)-decline analysis. Flowback data of these wells show up to 2 weeks of single-phase water production followed by hydrocarbon breakthrough. Plots of water-rate-normalized pressure and its derivative show pronounced unit slopes, suggesting boundary-dominated flow (BDF) of water in fractures during single-phase flow. Water PNR decline curves follow a harmonic trend during single-phase- and multiphase-flow periods. Ultimate water production from the forecasted harmonic trend gives an estimate of initial fracture volume. The estimates for these wells are verified by comparing them with the ones from the Aguilera (1999) type curves for natural fractures and experimental data. The results show that our estimates (4 to 22×10psi) are close to the lower limit of the values estimated by previous studies, which can be explained by the presence of proppants in hydraulic fractures.
Summary Reserves estimation is an essential part of developing any reservoir. Predicting the long-term production performance and estimated ultimate recovery (EUR) in unconventional wells has always been a challenge. Developing a reliable and accurate production forecast in the oil and gas industry is mandatory because it plays a crucial part in decision-making. Several methods are used to estimate EUR in the oil and gas industry, and each has its advantages and limitations. Decline curve analysis (DCA) is a traditional reserves estimation technique that is widely used to estimate EUR in conventional reservoirs. However, when it comes to unconventional reservoirs, traditional methods are frequently unreliable for predicting production trends for low-permeability plays. In recent years, many approaches have been developed to accommodate the high complexity of unconventional plays and establish reliable estimates of reserves. This paper provides a methodology to predict EUR for multistage hydraulically fractured horizontal wells that outperforms many current methods, incorporates completion data, and overcomes some of the limitations of using DCA or other traditional methods to forecast production. This new approach is introduced to predict EUR for multistage hydraulically fractured horizontal wells and is presented as a workflow consisting of production history matching and forecasting using DCA combined with artificial neural network (ANN) predictive models. The developed workflow combines production history data, forecasting using DCA models and completion data to enhance EUR predictions. The predictive models use ANN techniques to predict EUR given short early production history data (3 months to 2 years). The new approach was developed and tested using actual production and completion data from 989 multistage hydraulically fractured horizontal wells from four different formations. Sixteen models were developed (four models for each formation) varying in terms of input parameters, structure, and the production history data period it requires. The developed models showed high accuracy (correlation coefficients of 0.85 to 0.99) in predicting EUR given only 3 months to 2 years of production data. The developed models use production forecasts from different DCA models along with well completion data to improve EUR predictions. Using completion parameters in predicting EUR along with the typical DCA is a major addition provided by this study. The end product of this work is a comprehensive workflow to predict EUR that can be implemented in different formations by using well completion data along with early production history data.
Roussel, Nicolas (ConocoPhillips Company) | Swan, Herbert (ConocoPhillips Company) | Snyder, Jon (ConocoPhillips Company) | Nguyen, Dung (ConocoPhillips Company) | Cramer, David (ConocoPhillips Company) | Ouk, Annie (ConocoPhillips Company)
Abstract Instantaneous Shut-In Pressure (ISIP) is the pressure measured at the end of hydraulic stimulation, after friction pressure in the wellbore, perforations and near-wellbore region dissipates. ISIP data is a valuable source of insights on local stress conditions and geometrical characteristics of induced fractures and is systematically gathered during hydraulic fracturing operations at no additional cost. A new technique inspired from geophysical signal processing methods is proposed to automate the calculation of the instantaneous shut-in pressure. The proposed method isolates water-hammer oscillations from the pressure falloff behavior due to leakoff, equilibrium effects, and tip extension. The water hammer is seen as a damped harmonic oscillator, which is caused by pressure reverberations traveling through the pipe at the speed of sound in the wellbore fluid. The new algorithm was able to accurately capture not only shut-in pressure but also early-time pressure decay within the fracture system. The technique was applied to a large subset of wells in Eagle Ford and was then compared to the values of ISIP manually calculated by the service company engineer, as well as more traditional approaches, such as linear interpolation. Variability in post-treatment pressure data behavior, quality, and time frame has historically posed a challenge to automated algorithms, leading to significant errors in a large proportion of treatment stages. This simple yet novel approach is found to be more consistent and accurate in the face of those challenges than traditional algorithms and manual ISIP selections. The routine collection and interpretation of ISIP data has been employed to shed light on local reservoir stresses (pre- and post-depletion) and assess net fracturing pressure. By quantifying stress changes caused by depletion or stress shadowing, ISIP trends can provide information on parent well-child well interactions as well as the sequencing of fracturing operations across multiple wells. Introduction Instantaneous Shut-In Pressure (ISIP), or end-of-stage pressure, is a little bit of a misnomer, as authors of previous work have pointed out that shut-in pressures do not immediately stabilize following shut-in (McLennan and Roegiers 1982). For instance, frictional forces associated with near-wellbore flow may take several minutes to dissipate at the end of fracturing stage. Following shut-in, fluid inside the hydraulic fracture leaks off into the formation until closure on the proppant is achieved (Figure 1).
Abstract The ultimate recovery factor in tight and shale resources is limited and is usually in the range of 5-10%. Although high-intensity fracturing and refracturing can increase recovery, an enormous amount of oil will remain in place, hence the desirability of enhanced oil recovery methods. Many of the shale reservoirs are oil-wet with negligible water uptake. By altering the wettability, water can spontaneously imbibe into the formation matrix, creating a counter-current flow that forces the oil out. Here, we assess the likelihood of increased oil recovery by modifying the fracturing-fluid composition (salinity and ion concentration) that transforms the formation wettability into a more water-wet state. Oil wetting of tight formations is usually controlled by the adhesion of oil droplets on the surface of clay minerals. When clay minerals are not predominant, the oil attached to carbonate minerals can significantly control rock wettability. In this study, we first identify the primary reactions that define the initial wettability of the rock depending on the formation mineralogy, formation water composition, and oil type. Second, we build a geochemical model considering the surface complexation of various minerals to mimic the wettability state of the reservoir. Third, we validate our method on zeta-potential, contact angle, and imbibition data from a previously published study using different fluids with different salinities. Finally, we present a mechanistic approach to model the wettability-alteration impact on spontaneous imbibition and compute the incremental oil recovery contributed by different fracturing fluid compositions. Based on the studied case, the oil adhesion to clay can be reduced by tuning the fracturing fluid salinity. The ionic concentrations of 2.5 wt.% of NaCl and 5.0 wt.% of CaCl2 induced the smallest contact angles of 44.7 and 51.2 degrees. We observe that further brine dilution increases the contact angle. For example, distilled water shows the most oil-wet condition with a contact angle to 93.4 degrees. We argue that the main factors that maximize water wetting for the reported optimum salinities are the contrast in the rock and oil surface potential and the sodium concentration. Spontaneous-imbibition simulations indicate that the low salinity fluids promote a change in water-oil capillary pressure, leading to increased water uptake in the cores and improved oil recovery compared to distilled water. The agreement between the developed model and experimental data implies that the wettability in shale and tight formations can be quantitatively predicted and regulated.
Benge, Margaret (Oklahoma State University) | Lu, Yunxing (Oklahoma State University) | Katende, Allan (University of Pittsburgh) | Rutqvist, Jonny (Lawrence Berkeley National Laboratory) | Crandall, Dustin (National Energy Technology Laboratory) | Haecker, Adam (Continental Resources) | King, George (GEK Engineering) | Renk, Joseph B. (National Energy Technology Laboratory) | Radonjic, Mileva (Oklahoma State University) | Bunger, Andrew (University of Pittsburgh)
Abstract The Caney Shale is emerging as a target for hydrocarbon production, creating opportunities to study rock mechanical origins of observed/anticipated challenges to effective and sustained stimulation. Here we examine five subunits within the Caney, two of which are dubbed "ductile" and three of which are dubbed "reservoir" rock types. The "ductile" versus "reservoir" identification is initially based on elastic properties ascertained from well logs. By comparing core-based mechanical tests, it is found nominally ductile and reservoir layers do not differ in terms of brittleness, but instead the nominally ductile layers tend to be weaker and more prone to creep deformation compared to the nominally more brittle reservoir layers. This difference in mechanical properties is shown to generate higher susceptibility to proppant embedment in the weaker and more creep-prone layers. Specifically, over a 5-year period, the creep is expected to have little impact on reservoir layers but is predicted to reduce propped fracture aperture by a factor of 2 in the ductile layers. Introduction The Caney shale is located in southwest Oklahoma, located below the Springer shale and above the Woodford shale formations (Cardott, 2017). Recent attention has turned to the Caney as an emerging target for hydrocarbon production. Some of the main challenges are thought to be related to high clay content (Awejori et al, 2021, Radonjic et al, 2020) and the presumably ductile behavior with negative implications for effectiveness of stimulation. However, recently it has been argued (Benge et al, 2021) the Caney is not demonstrably "ductile" by the typical measures of brittleness/ductility ascribed to rocks. Hence, a more thorough mechanical study is required to highlight challenges associated with stimulation/production from the Caney so solutions can be developed to suit the specific challenges. Firstly it is necessary to revisit what is meant by the terms "brittle" and "ductile". While such terminology is often used in a casual sense, there are at least two relevant mechanical definitions. One definition compares the peak and residual strength of a material (Bishop, 1967). Brittle materials lose strength abruptly when subjected to stress (i.e. tensile and/or shear) which exceeds the peak strength of the material, while ductile materials maintain a residual strength which can be nearly equal to the peak strength. Another definition has its roots in fracture mechanics, with brittle materials considered to ascribe to the assumption inelastic strain is confined to a very small region near a propagating crack tip (as compared to the crack length) and the energy required for crack propagation is assumed to be an intrinsic property of the material (e.g. see discussion in Papanastasiou and Atkinson, 2015).