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Collaborating Authors
Results
Investigating Well Interference in a Multi-Well Pad by Combined Flowback and Tracer Analysis
Fu, Yingkun (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Ezulike, Obinna (University of Alberta) | Virues, Claudio (Nexen Energy ULC) | Bearinger, Doug (Nexen Energy ULC)
Abstract This study presents a workflow for identifying and evaluating well interference, and investigating how interference affects fracture cleanup in a multi-well pad. We analyze flowback pressure and tracer data from a 10-well pad completed in three shale members of the Horn River Basin. Three key steps are used in this study: First, we analyze the tracer concentration profiles to investigate well interference in the pad before flowback. Second, we compare the casing pressure of the wells during selective shut-in and re-opening to investigate well interference during flowback and post-flowback periods. Third, we construct diagnostic plots of gas-water ratio (GWR) to see how well interference affects fracture cleanup during flowback. We observe that well interference in the pad occurs in three stages – before flowback, during flowback and during post-flowback. Before flowback, concentration profiles from some wells show early breakthrough of tracers injected into neighboring wells in the pad. Analysis of the tracer data suggests that fracturing operations create connecting pathways among the wells in the pad. During flowback and post-flowback, we observe that the shut-in and re-opening of some wells in the pad disturb the recorded pressure in the remaining wells. The log-log plots of GWR versus cumulative gas production for late-opened wells show an approximate half-slope, suggesting fracture cleanup. However, this trend of fracture cleanup is not observed for the early-opened wells. This shows that the early-opened wells drain fracturing water from the late-opened wells through connected fractures, when the wells in a pad are opened for flowback in a sequence. Combined analysis of flowback and tracer data helps to understand how fracturing water migrates between wells, and to optimize well placement in a pad. Introduction "Frac-hit" is a common phenomenon when multi-fractured horizontal wells are tightly spaced in an unconventional reservoir. Frac-hit is a rapid pressure increase in wells that are shut-in during the fracturing treatment of offset wells. Well interference during fracturing operations has been identified and evaluated using the pressure increase during frac-hit (Sardinha et al. 2014; Lehmann et al. 2016). However, it is not clear if the well interference caused by frac-hit is sustained after fracturing treatment, and how it affects hydrocarbon production.
- North America > United States (1.00)
- North America > Canada > Alberta (0.47)
- North America > Canada > British Columbia (0.35)
Fracture Network Characterization by Analyzing Flowback Salts: Scale-Up of Experimental Data
Zolfaghari, Ashkan (University of Alberta) | Tang, Yingzhe (University of Alberta) | He, Jia (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Bearinger, Doug (Nexen Energy ULC) | Virues, Claudio (Nexen Energy ULC)
Abstract As observed in many shale-gas plays, the produced flowback water is highly saline and the salt concentration increases with time. Several past studies investigated water-rock interactions to interpret flowback chemical data, evaluate reservoir performance, and investigate the environmental impacts of fracturing operations. In this study, we measure the total ion produced (TIP) during flowback process for two wells completed in the Horn River Basin. We also conduct two sets of imbibition experiments to investigate the effects of water-rock surface area (As) and rock volume (Vs) on the TIP in laboratory. Furthermore, we compare the experimental correlations between As - TIP and Vs - TIP with the TIP measured in the field flowback water to estimate fracture surface area (AFrac) and invaded reservoir volume (IRV). In order to investigate the effect of As on the TIP, we conduct a series of imbibition experiments using shale samples of different As but similar Vs at constant temperature. The experiments are performed at T = 23, 45, and 65°C to investigate the temperature effect on the TIP. The experimental correlation between TIP and As at constant temperature is applied to estimate AFrac using field data of TIP. We further utilize AFrac - T correlation to extrapolate AFrac at reservoir temperature. In order to evaluate the estimated AFrac values we also calculate AFrac by rate-transient-analysis (RTA). In order to investigate the effect of Vs on the TIP, we conduct a series of imbibition experiments using shale samples of different Vs but similar As at constant temperature. Experimental results indicate that the TIP increases with both As and temperature. The calculated AFrac value at reservoir temperature is approximately 10m for both target wells. These results are in agreement with RTA calculation of AFrac values for both target wells (≈ 10m). Our estimated values of AFrac are also in agreement with the field data of water recovery. The well with higher estimated value of AFrac has lower water recovery in the field as opposed to the well with lower estimated value of AFrac and higher water recovery in the field. Additionally, the estimated IRV is approximately 10 - 10m for both target wells. Our estimated values of IRV are also in agreement with the field data of water recovery and experimental results of water uptake. The well with higher estimated value of IRV has higher water uptake during imbibition experiments and also higher leak-off rate in the field. In contrast, the well with lower estimated value of IRV has lower water uptake during imbibition experiments and also lower leak-off rate in the field.
- North America > United States > West Virginia (0.68)
- North America > Canada > British Columbia (0.48)
- North America > Canada > Alberta (0.47)
- North America > United States > Pennsylvania (0.46)
- Geology > Geological Subdiscipline (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.67)
- Geology > Mineral > Silicate > Phyllosilicate (0.47)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.34)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (8 more...)
Experimental Investigation for Microscale Stimulation of Shales By Water Imbibition During the Shut-in Periods
Gupta, Aadish (University of Alberta) | Xu, Mingxiang (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Bearinger, Doug (Nexen Energy ULC)
Abstract Imbibition of water into the shale matrix is known as the primary reason for inefficient water recovery after hydraulic fracturing treatments. The hydration of clay minerals may induce microfractures in clay-rich shale samples. The increased porosity and permeability due to induced microfractures has been considered to be partly responsible for 1) excessive water uptake of gas shales, and 2) increase in hydrocarbon production rate after prolonged shut-in periods. To test this hypothesis, it is necessary to measure imbibition-induced strain and stress under representative laboratory conditions. In this study, we conduct laboratory tests to 1) measure the strain and stress induced by water imbibition in gas shales and 2) investigate the effect of confining load on the rate of water imbibition. We conduct a three-phase study on rock samples from the Horn River Basin (HRB) and the Duvernay (DUV) Formation, located in the Western Canadian Sedimentary Basin. In the first phase, we measure baselines for water and kerosene imbibition into the rock samples by conducting spontaneous imbibition tests. In the second phase, we measure expansion of the rock samples during imbibition of water and kerosene, in separate tests, using a linear variable differential transformer (LVDT). In the third phase, we measure imbibition-induced tensile stress during water imbibition into the samples. The results show that both HRB and DUV shale samples imbibe more water than kerosene, due to water adsorption by clay minerals. Imbibition of water increases the porosity of the HRB and the DUV samples by up to 0.94 and 0.25 percentage points, respectively. Expansion of all samples is anisotropic, with higher expansion perpendicular to the depositional lamination. Water imbibition into the samples induces an expansive stress as high as 17 psi. Moreover, applying confining stress reduces the imbibition of water by up to 18.1% and 33.7% in the HRB and DUV samples, respectively.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > Canada Government (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Complementary Surveillance Microseismic and Flowback Data Analysis: An Approach to Evaluate Complex Fracture Networks
Xu, Yanmin (University of Alberta) | Ezulike, Obinna Daniel (University of Alberta) | Zolfaghari, Ashkan (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Virues, Claudio (Nexen Energy ULC)
Abstract This paper presents an integrated workflow which complementarily utilizes flowback data analysis and surveillance microseismic analysis to characterize fracture networks and stimulated reservoir volume (SRV). The workflow helps to 1) differentiate !"effective" and "ineffective" SRV and fracture half-length (ye) respectively, 2) understand how effective fracture volume (Vf) changes during flowback, and 3) explore the effects of key operational parameters on the fracture network created after well stimulation. The workflow comprises four main steps: 1) estimating SRV and fracture parameters from surveillance microseismic interpretation and flowback data analysis; 2) comparative analysis of estimated SRV, ye and Vf values; 3) Calculating volumetric ratios (e.g. flowback load recovery) to evaluate the effectiveness of fracturing and flowback operations; and 4) investigating possible relationships between operational designs and estimated reservoir and fracture parameters. The application of this workflow on an eight-well pad completed in the Horn River Basin (HRB) shows that the SRV and ye from microseismic interpretation are generally several times larger than those from flowback data analysis. This indicates that over half of the stimulated rock does not contribute to gas production. Besides, a large percentage of the effective fracture network closes during early-time (the first 200 hrs) flowback. The results show that SRV increases as total perforation clusters increases, and this relationship appears to be formation-dependent. Also, the estimated Vf seems to be smaller for wells that are opened later for flowback. This observation might be due to inter-well communication and wellbore storage effects.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- North America > United States > Texas (0.94)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.30)
Fracture Characterization Using Flowback Salt-Concentration Transient
Zolfaghari, Ashkan (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Ghanbari, Ebrahim (University of Alberta) | Bearinger, Doug (Nexen Energy ULC)
Summary As observed in many shale-gas operations, salt concentration of flowback water increases with time. Usually, the shape of salt-concentration/load-recovery plots is different from one well to another. We hypothesize that the shape of the salinity profile during the flowback process provides useful information about the complexity of the fracture network. In this study, we propose a model to describe the relationship between salinity and cumulative water production. We also compare the model results and flowback-salinity data to characterize the fracture network. Flowback-salinity data are collected from three multifractured horizontal wells completed in the three shale members [Muskwa (Mu), Otter-Park (OP), and Evie (Ev)] of the Horn River Basin. The salinity profiles for the Mu and OP wells initially increase and finally reach a plateau, whereas the salinity profile for the Ev well shows a continuous increase and does not show a plateau. We hypothesize that the early water with lower salt concentration at the onset of the flowback process is mainly produced from the primary fractures with larger aperture size. Also, we believe that the fractures with smaller aperture size become more important as the flowback process progresses, and therefore, the high-salinity water produced at later times is mainly produced from secondary fractures. We also propose a model to describe the salinity-profile behaviors. The model presents the aperture-size distribution (ASD) of the fracture network. A comparative analysis of the model results and the flowback-salinity data indicates that the Ev well with a steady increase in its salinity profile has a wider ASD compared with the Mu and OP wells with a plateau in their salinity profiles. This suggests that the fracture network is more complex in Ev compared with those in Mu and OP. More-complex fracture network in Ev is also in agreement with its higher gas and lower water recovery during the flowback process as opposed to the lower gas and higher water recovery in Mu and OP. The presented model for describing the behavior of the salinity profile during the flowback process and its meaningful relationship to the fracture-network complexity provide an alternative approach for reservoir characterization. This study encourages the industry to manage the flowback operations carefully and to monitor the water chemistry.
- North America > Canada > British Columbia (1.00)
- Europe (1.00)
- North America > United States > Texas (0.93)
- North America > Canada > Alberta (0.69)
- Geology > Mineral (0.94)
- Geology > Geological Subdiscipline > Geomechanics (0.83)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.71)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (7 more...)
Advances in Flowback Chemical Analysis of Gas Shales
Zolfaghari, Ashkan (University of Alberta) | Tang, Yingzhe (University of Alberta) | Holyk, Jordan (University of Alberta) | Binazadeh, Mojtaba (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Bearinger, Doug (Nexen Energy ULC)
Abstract Recently, flowback chemical analysis has been considered as a complementary approach for evaluating fracturing operations and characterizing reservoir properties. Understanding the source of flowback salts and the mechanisms controlling the water chemistry is essential but also challenging due to the complexity of shale-water interactions. In this study, samples of flowback water and downhole shales are analyzed to investigate the mechanisms controlling the chemistry of flowback water. The water samples at different flowback times and the shale samples are collected from three wells completed in the Muskwa, Otter-Park, and Evie members of the Horn River Basin. The water samples consist of aqueous solution and precipitated salts. The water samples are digested in nitric acid to dissolve the precipitated salts, and are analyzed at both intact and acid-digested conditions using ICP-MS. The flowback salts are weighted and analyzed using XRD and SEM-EDXS. A sequential ion-extraction is performed on the shale samples; and the extracted ions are categorized into three tiers of loosely-, moderately-, and strongly-attached ions. The concentration of monovalent cations in both intact and acid-digested samples is higher than that of divalent cations. Also, the concentration of all cations is higher in the acid-digested samples compared with that in the intact samples. The ratio of divalent cations concentration in the acid-digested samples to that in the intact samples is higher than that for the monovalent cations. This ratio increases for the divalent cations over time, while it remains constant for the monovalent cations. Additionally, for the acid-digested samples the monovalent cations concentration has an initial sharp increase followed by a slower increase at later flowback stages; while the divalent cations concentration increases continuously over time. These results suggest that the majority of the ions in the early flowback water are loosely-attached monovalent ions. These ions can be originated from the mixing with in-situ formation brine, dissolution of soluble precipitated salts, or leaching of exchangeable cations from the clay minerals. Similarly, the role of relatively slow water-rock interactions (such as leaching of divalent exchangeable cations, e.g. Ca,) increases at the later flowback stages. XRD and SEM-EDXS analyzes of the flowback salts indicate that sodium chloride, potassium chloride, and calcium carbonate are the major salts. The sequential ion-extraction reveals that the majority of the monovalent cations are in the loosely-attached tier. However, majority of the divalent cations are moderately- /strongly-attached to the rock. The strongly-attached portion of the ions is determined by acid digestion of the rock sample at the final stage of sequential extraction process. These strongly-attached ions cannot be easily released by hydraulic fracturing and therefore, has small effect on the flowback water chemistry.
- North America > United States > West Virginia (1.00)
- North America > Canada > British Columbia (0.87)
- North America > United States > Pennsylvania (0.68)
- North America > Canada > Alberta (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (11 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Understanding the Origin of Flowback Salts: A Laboratory and Field Study
Zolfaghari Sharak, Ashkan (University of Alberta) | Noel, Mike (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Bearinger, Doug (Nexen Energy ULC)
Abstract Several past studies have focused on the saline flowback water to evaluate the hydraulic fracturing operations. The origin of the salts in the flowback water is important for the assessment of the flowback process. In this study, laboratory and field analyses are performed to provide a better understanding about the origin of the flowback salts. The field study analyzes the total salt concentration (salinity) and ion concentration data measured during the flowback process for the Muskwa (Mu), Otter-Park (OP), and Evie (Ev) formations. The concentration profiles of both the barium and chloride during the flowback process, whereas the iron concentration declines after experiencing an initial increase. The laboratory study encompasses contact angle, XRD, imbibition, individual ion concentration, surface element, and adsorption isotherm experiments for samples from the OP and Ev formations. To investigate the effects of fluid-rock interface area on the liquid uptake and diffusion rate of individual ions, a series of imbibition experiments are carried out for different values of surface to volume ratios (specific surface or "Asp"). The electrical conductivity and individual ion concentrations are measured during the imbibition process. XRD data is analyzed to determine the mineralogy of the samples. SEM-EDX analysis is performed to determine the distribution of the elements on fresh break and natural fracture surfaces of the samples (in addition to a sample from the Lower Keg (LK) formation). Finally, since both ion transfer and water adsorption processes occur during the imbibition experiment, an adsorption isotherm experiment is carried out to prevent the ion transfer into/out of the rock in order to solely study the water adsorption process. The laboratory results show that barium is mainly concentrated in the natural fractures; and therefore the shape of the barium concentration profile in the flowback water maybe an indication of the complexity of the fracture network.
- Europe (0.93)
- North America > United States > Texas (0.68)
- North America > Canada > British Columbia (0.48)
- North America > Canada > Alberta (0.47)
- Geology > Geological Subdiscipline > Mineralogy (0.51)
- Geology > Mineral > Silicate > Phyllosilicate (0.48)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (5 more...)
Advances in Understanding Liquid Flow in Gas Shales
Ghanbari, Ebrahim (University of Alberta) | Xu, Mingxiang (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Bearinger, Doug (Nexen Energy ULC)
Abstract Understanding water uptake of gas shales is critical for designing fracturing and treatment fluids. Previous imbibition experiments on unconfined gas shales have led to several key observations. The water uptake of dry shales is higher than their oil uptake. Furthermore, water imbibition results in sample expansion and microfracture induction. This study provides additional experimental data to understand the effects of rock fabric, complex pore network, and clay swelling on imbibition behavior. We systematically measure the imbibition rates of fresh water, brine and oil into the confined and unconfined rock samples and crushed packs from different shale members of the Horn River Basin. We also measure the ion diffusion rate from shale into water during imbibition experiments. The results show that confining the shale samples decreases the water imbibition rate of samples tested parallel to the bedding. However, it has a negligible effect on water uptake of samples tested perpendicular to the bedding and on ion diffusion rates. The comparative study suggests that, for both confined and unconfined samples, water uptake is higher than oil uptake. The liquid imbibition and ion diffusion rates along the bedding are higher than those against the bedding. Surprisingly, the crushed samples show a completely different behavior. The oil uptake of crushed packs is higher than their water uptake. The data suggest that the connected pore network of the intact samples is water wet while the majority of rock including poorly connected pores is oil wet. This argument is backed by complete spreading of oil on fresh break surfaces of the rock.
- North America > United States (1.00)
- North America > Canada > British Columbia (1.00)
- Research Report > Experimental Study (0.67)
- Research Report > New Finding (0.48)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Fracture Architecture from Flowback Signature: A Model for Salt Concentration Transient
Zolfaghari Sharak, Ashkan (University of Alberta) | Ghanbari, Ebrahim (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Bearinger, Doug (Nexen Energy ULC)
Abstract It has been observed in many shale gas operations that salt concentration of flowback water increases with time. Usually, the shape of concentration-time plots is different from one well to another. It is hypothesized that the relationship between salt concentration and cumulative water production provides useful information about the architecture of the fracture network. However, there is no simple analytical model available in the literature for quantitative interpretation of the measured salt profiles, and for evaluating fracturing operations. In this study, two mathematical models are proposed for history-matching the salt concentration data measured during flowback operations and for investigating the complexity of fracture network. The models describe a relationship between cumulative water production and salt concentration, which in turn is related to the fracture aperture, is mathematically described. The two models describe a relationship between salt concentration profile and aperture size distribution (ASD) of the fracture network. The first model gives the volumetric fraction (as a probability density function) of each fracture aperture. The second model considers a bundle of fractures in series to derive the probability density function. The salt concentration during the flowback operation of three multi-fractured horizontal wells completed in the three shale members of the Horn River basin is measured. The comparative study of concentration profiles suggests a meaningful relationship between the profile shape and the complexity of fracture network. For wells, with simple hydraulic fractures, the concentration profile reaches to a plateau. However, for wells with more complex fractures, the concentration profile keeps increasing and does not show a plateau. The proposed mathematical models are able to describe and quantify this behavior. Both models have almost the same ASD predictions. The mathematical modeling results show that the ASD is narrower when the concentration-load recovery plots reach to a plateau and therefore the fracture network is simple. However, when the concentration-load recovery plots shows a steady increase; ASD is wider and the facture network is complex. The presented field study and the proposed mathematical models develop an improved understanding of hydraulic fracture systems. This study provides an alternative approach for evaluating fracturing operations and encourages the industry to manage the flowback operations carefully and monitor the water chemistry.
- North America > United States > Texas (1.00)
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (0.70)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.56)
Abstract Field studies demonstrate low flowback efficiency determined by volumetric analysis of injected and recovered fracturing water. However, the reasons for inefficient water recovery, and its impact on short-term and long term production are poorly understood. Furthermore, volumetric water analysis is not sufficient for determining the source of recovered water and the true load recovery. This paper aims at understanding how flowback efficiency is related to the imbibition process, presence or absence of natural fractures, and the complexity of induced fracture network. We interpret the flowback rate and salt concentration, measured from several multi-fractured horizontal wells recently completed in different members of the Horn River basin. We also measure and analyze water imbibition and salt diffusion rate in actual cores drilled from the same shale members. The wells are classified into those with 1) low water and high gas production, 2) high water and low gas production. This classification is explained by lab imbibition data and possible fracture patterns. Furthermore, the flowback salt concentration change is explained by the diffusion data measured in the laboratory. This systematic study provides a practical database for understanding the factors impacting the water recovery that will potentially help the operators to optimize the flowback operations, and obtain useful information about the induced fracture network.
- North America > Canada > British Columbia (1.00)
- North America > United States > Texas (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.56)
- Geology > Mineral > Silicate (0.49)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)