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Collaborating Authors
Results
Binary Mixture Thermo-Chemical (BiMTheCh) Technology for Development of Low-Permeable Formations of Oil Fields in Caspian Sea
Koochi, M. Rezaei (Petroleum engineering department, Kazan Federal University, Russia) | Rojas, A. (Petroleum engineering department, Kazan Federal University, Russia) | Varfolomeev, M. A. (Petroleum engineering department, Kazan Federal University, Russia) | Khormali, A. (Chemistry department, Gonbad Kavoos University, Iran) | Lishcuk, A. N. (HMS Group Company, Moscow, Russia)
Abstract Binary mixture thermo-chemical (BiMTheCh) technology refers to energy-releasing chemicals which can be injected into the reservoir with in-situ generation of heat, nitrogen and carbon dioxide. As laboratory investigations show, BiMTheCh or thermochemical fluid has proved to be a highly effective technology for stimulation of oil wells with heavy oil and low permeability. In this work, the feasibility of this technology for stimulation of brown fields from laboratory to field scale is investigated. First, on the laboratory scale, thermobaric parameters of the reaction were studied to optimize the composition of injecting chemicals. And finally, the optimized composition is applied to enhance oil recovery from low permeable reservoirs in Russia. Laboratory results show that BiMTheCh can be used for removing asphaltene and resin from near borehole zone by melting them. Generated gases after the reaction create a network of fractures in the vicinity of the reaction zone and simultaneously, by inducing a thermobaric shock, cracks oil molecules and upgrades oil directly into the reservoir. Oil field data in 5 wells shows that oil production increased 2-3 folds with a duration of 12 months or more. BiMTheCh can be used for stimulation of green and brown fields with a high efficiency in a safe rig-less mode.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (5 more...)
Subsurface Injection Monitoring in Complex Geologic Media Using Pathline, Source Cloud and Time Cloud
Li, Ao (Texas A&M University, College Station, Texas, USA) | Chen, Hongquan (Texas A&M University, College Station, Texas, USA) | Jalali, Ridwan (Saudi Aramco, Dhahran, Saudi Arabia) | Al-Darrab, Abdulaziz (Saudi Aramco, Dhahran, Saudi Arabia)
Abstract Monitoring of subsurface fluid motion is critical for optimizing hydrocarbon production and CO2 sequestration. Streamlines are frequently employed to visualize fluid flow; however, they provide only an instantaneous snapshot of the velocity field and do not offer an exact representation of fluid movement under varying field conditions. In contrast, pathlines are constructed by tracking individual particles within the fluid, enabling us to trace the movement of these particles as they traverse through changing velocity fields. This paper presents the development and application of pathlines for flow visualization in complex geologic media. The flow visualization is further aided by source cloud (streak lines) and time cloud (isochrones representing moving fluid fronts). We demonstrate the power and utility of the developed tool in fractured media using Embedded Discrete Fracture Model (EDFM). Pathlines track the history of flowing particles in the reservoir. Pathlines can be spliced from streamline segments over time, tracing the trajectory of a particle under changing velocity fields. For each interval, a pathline’s end is extended with a streamline segement whose elapsed time of flight (TOF) equals the time interval. Based on the pathlines, streaklines and timelines can also be visualized. Streakline is formed by all fluid particles emitted at the same location. Timeline is the contour formed by all fluid particles emitted at the same instant and represents the fluid front movement. In 3D, these two concepts are more generally visualized in groups of points rather than lines, so we refer to them as source cloud and time cloud. The proposed injection monitoring methods - Pathline, Source Cloud and Time Cloud - are tested using a 3D field-scale model with complex geologic features to demonstrate its power and utility. The pathlines were compared with streamlines, time of flight and the water saturation distribution. Three scenarios are tested: a constant well schedule, a changing well schedule with shut-ins, and a changing well schedule with fully injection cease. Results indicate that the pathline provides more accurate swept volume, consistent with saturation distribution. The robustness of our algorithm and implementation is demonstrated with a complex Embedded Discrete Fracature Model (EDFM) with non-neighbor connections to visualize flow patterns in discrete facture network. Pathlines display the fluid flow across fractures and are subsequently used to examine the sweep efficiency and the well connectivity.
- Asia > Middle East > Saudi Arabia (0.46)
- North America > United States > Texas (0.28)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Streamline simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
A Two-Phase Type-Curve Method with Fracture Damage Effects for Hydraulically Fractured Reservoirs
Zhang, Fengyuan (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum-Beijing, Beijing, China) | Pan, Yang (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum-Beijing, Beijing, China) | Rui, Zhenhua (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum-Beijing, Beijing, China) | Emami-Meybodi, Hamid (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, State College, Pennsylvania, USA) | Yang, Chia-Hsin (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, State College, Pennsylvania, USA) | Wang, Ruiqi (Department of Oil Field Development, Research Institute of Petroleum Exploration & Development, Beijing, China) | Zhang, Wei (Department of Geoscience, University of Calgary, Calgary, Alberta, Canada)
Abstract Type-curve analysis on flowback and production data is a powerful tool in characterizing hydraulic fractures (HF) and reservoir properties. In order to evaluate HF characteristics and their dynamics for multi-fractured horizontal wells (MFHWs) in hydrocarbon reservoirs, we provide a novel type-curve method and an iterative workflow. The type curve incorporates the fracture damage effect, which is characterized by choked-fracture skin factor, into the two-phase flow in HF and matrix domains. The type-curve method can be applied to inversely estimate choked-fracture skin factor, fracture pore-volume, fracture premeability, and fracture permeability modulus through the analysis of two-phase production data. By introducing the new dimensionless parameters, the non-uniqueness problem of the proposed semianalytical method is significantly reduced by incorporating the complexity of fracture dynamics into one set of curves. The proposed type curve's accuracy is examined by numerical simulations of a shale gas and shale oil reservoir. The validation results demonstrate the good match of analytical type curves and numerical data plots and confirms the accuracy of the proposed approach in estimating the static and dynamic fracture properties. The flexibility and robustness of the proposed method are illustrated using the field example from a shale oil MFHW. The interpreted results from the flowback analysis of the field example offers a quantitative insight of fracture properties and dynamics.
- North America > United States (1.00)
- North America > Canada > Alberta (0.28)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.90)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Block 628 > Julia Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Block 627 > Julia Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Block 584 > Julia Field (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (8 more...)
Efficient fully coupled 3D poroelastic modeling of geomechanical deformation during depletion and reinjection: An asymptotic transformation of Biot’s poroelasticity from a dynamic to a quasistatic response
Shabelansky, Andrey H. (Chevron Technical Center) | Nihei, Kurt T. (Chevron Technical Center) | Fradelizio, Gian (Chevron Canada Resources) | Tracey, Sinead (Chevron Canada Resources) | Bevc, Dimitri (Chevron Technical Center)
ABSTRACT We develop an approach for efficient 3D simulation of the quasistatic fully coupled poroelastic response of a reservoir during depletion and subsequent reinjection. The approach uses a scaling of the solid and fluid densities in Biot’s poroelastic equations. This scaling impacts the critical frequency of Biot’s slow wave that defines diffusive flow () and wave propagation (). We find the criterion for the density scaling range over which the poroelastic response is accurately modeled and benchmark the approach against Terzaghi’s 1D and Rudnicki’s 3D analytic solutions. The density scaling approach is presently limited to single-phase fluid flow. To illustrate the utility of this approach, we simulate microseismic depletion delineation (MDD) in a fractured unconventional reservoir. The reservoir, which is subjected to an anisotropic stress field, is first produced for 1000 days, and then a reinjection (below the in situ pressure) is performed for 100 days. We find that stress reorientation during production produces favorable conditions for the generation of Mohr-Coulomb slip-related microseismicity. The locations of these microseismic events are found to be consistent with depleted portions of the fracture system, in accordance with the MDD concept.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.28)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Duvernay Field > Duvernay Formation > Acl Duv 13-12-57-13 Well (0.98)
- Europe > Italy (0.91)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (3 more...)
ABSTRACT Horizontal drilling and multi-stage/multi-cluster hydraulic fracturing are critical technologies that enable the economic production of hydrocarbons from unconventional reservoirs. However, achieving uniform growth from multiple perforated clusters remains a challenge. In hydraulic fracturing operations, some fractures can be overgrown while others are fully suppressed. Near-wellbore diversion is commonly used to promote uniform growth of each cluster in a stage. In this study, a continuum approach of particle transport was implemented and coupled with a fluid flow solver in FLAC to simulate the nonlinear particle propagation and bridging in the near-wellbore diversion process. The effect of swelling behavior of diverters on the bridging location and time inside a fracture, as well as pressure buildup at the fracture entrance, was evaluated. Simulation results showed that the use of swelling particles resulted in the formation of a closed bridging loop with fewer particles and a shorter injection time, and higher fluid pressure at the fracture entrance. INTRODUCTION Horizontal drilling and multi-stage/multi-cluster fracturing have become standard practices for the completion of unconventional reservoirs (Economides and Nolte, 2000). However, due to the heterogeneity of the formations, local stress concentration from geological structures, and stress interference from nearby fractures, uneven growth of multiple fractures is commonly observed in the field (Cipolla et al., 2011; Miller et al., 2011). To promote uniform growth, hydraulic fracturing operations often use diverting particles that temporarily block off the over-grown fractures, allowing more injected fluid to be diverted to under-stimulated fractures (Barraza et al., 2017; Daneshy, 2019; Shahri et al., 2016). Numerical modeling is a valuable tool for understanding, predicting, and designing hydraulic diversion operations. The numerical schemes to model particle transport can be classified into two groups: discrete and continuum approaches. While the discrete approach (Mao et al., 2021; Mondal et al., 2016; Suri et al., 2020; Zeng et al., 2019) has demonstrated accuracy in capturing fluid-particle interactions at the pore-scale and applications in investigating problems related to fluid flow through proppant packs and sand erosion inside fractures and perforations (Fan et al., 2019, 2018; Han and Cundall, 2013, 2011), it suffers from a major drawback of high computational cost.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Well Drilling > Drilling Operations > Directional drilling (0.69)
- (2 more...)
ABSTRACT Modeling of fluid flow in rock fractures is a key issue in answering numerous geoengineering problems in the fields of geophysics, reservoir engineering, rock mechanics, to geothermal processes. Although fluid flow in single fractures has been extensively studied in the last 7 decades, fractures commonly seen in fractured reservoir systems intersect each other forming complex geometric structures. Such fracture networks likely affect fluid flow behavior and solute transport. To investigate the impact of geometric characteristics of connected rough-walled fractures with an X junction shape on linear and nonlinear fluid flow behaviors, a sensitivity analysis was carried out by conducting a series of numerical fluid flow simulations on X shape fractures, generated by scanning real rock fractures with distinct roughness (low, medium, and high), intersecting angles, and apertures. The fluid flow through these fractures at different flow rates was simulated by solving Naiver-Stokes equations. The results show that tortures paths and the formation of eddies are more accentuated on the rough fracture than the smoother ones, and the tortuosity of the streamlines is related to the roughness and the geometric characteristics of the intersection. Simulation results of the different models were compared, which show that the intersection significantly impacts the relationship between the hydraulic gradient and the flow. Therefore, the pressure gradient increases with the decrease of the intersection angle especially for low aperture and rough cases. INTRODUCTION Understanding fluid flow through a fractured rock mass has great importance to numerous underground industrial activities, such as geothermal extraction (Zhao, 2016), CO2 storage (Catherine Noiriel et al., 2013), oil and gas exploration (Bo Li et al., 2016), underground oil storage (Qiao et al., 2017; Wang et al., 2015), and hydraulic fracturing (Blanton TL,1982). It is important to measure the impact of roughness to improve the performance of large-scale models since most existing large-scale models still rely heavily on simplified smooth parallel-plate models and related models for natural rock fractures with rough walls (Zimmerman et al., 1992; Zimmerman and Bodvarsson, 1996; Ge 1997; Bodin et al., 2007; Zhao et al., 2013; Wang et al., 2015).
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
ABSTRACT A novel formulation for a symmetric cohesive element is presented here, for hydraulic fracture modeling problems that involve one fluid driven crack with a plane of symmetry coinciding with the fracture plane. The formulation enables analyses by modeling only half the domain for such problems. The modeling framework employed is the recently developed 3D finite element model in Abaqus which fully couples the rock deformation with the pore fluid Darcy flow. The symmetric cohesive element is an enhanced version of the previously developed 3D pore pressure cohesive element, uniquely capable of simulating Darcy flow in the undamaged state and a smooth transition to a tangential Poiseuille flow when damaged completely. Flow into the formation/fracture is modeled via specialized 1D pipe elements that can account for the wellbore fluid flow and frictional losses. Fluid leak-off into the formation is also modeled by means of a filter cake leak-off coefficient. The symmetric cohesive element is formulated by imposing appropriate constraint conditions on the displacement and pore pressure degrees of freedom, that enforce symmetric crack face behavior on either side of the fracture plane, i.e., the plane of symmetry. In addition, appropriate scaling factors are applied to various model parameters viz. the rock fracture energy, the pipe diameter, pipe friction factor and last but not the least, the viscosity of the fracturing fluid. The proposed approach with the aforementioned constraints and scaling factors is demonstrated to correctly simulate just half the domain of a symmetric hydraulic fracture, and yield results virtually identical to the full model, at half or less computational cost. Both lab and field scale examples are presented to demonstrate the effectiveness of the proposed approach. INTRODUCTION Symmetry has long been exploited in mechanics to simplify problem solving and to reduce domain and model sizes during numerical analysis e.g., using finite element method (FEM). For instance, it is common to employ an axisymmetric solution to engineering problems with a radial symmetry. In many problems involving fractures, the plane of the fracture is also a plane of symmetry, e.g., in three-point bending of a simply supported notched beam, or during delamination of a double cantilever beam (DCB). In these analyses, it suffices to model just one half of the structure and one face of the fracture, thus reducing the computational cost by half. However, while doing so, there are some additional considerations required to ensure that the solution is the same as that from the full domain. E.g., when the fracture is modeled using cohesive elements, additional constraint conditions on the displacements must be enforced, as discussed in Brocks et. al (2013) and Abaqus manual (2016), so that the displacements (openings) of top and bottom surfaces of cohesive elements are equal, to guarantee a symmetric fracture opening. Due to these constraints, the specified cohesive strength (which can be expressed as a function of the Young's modulus and fracture energy) needs to be reduced to half, to obtain the same results as the full model.
- North America > United States (0.94)
- Europe > Norway > Norwegian Sea (0.24)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
Evaluating the Geothermal Potential of Hot Sedimentary Aquifers Using a Hybrid Approach
Cottrell, Mark (WSP UK Limited) | Lacazette, Alfred (Geothermal Technologies Inc.) | Chmela, Bill (Geothermal Technologies Inc.) | Karimi, Saman (Geothermal Technologies Inc. / Johns Hopkins University) | Marsh, B. D. (Geothermal Technologies Inc. / Johns Hopkins University)
ABSTRACT Flow through geothermal reservoirs is highly complex, and often includes contributions from both fracture networks and the porous rock matrix. Discrete Fracture Network (DFN) models are proven, effective tools for the characterization of rock masses especially where fracture dominated fluid flow is encountered; whereas more conventional tools, such as Finite Volume (FV) methods, are more numerically favorable for simulating problems where detailed multiphysics is required. This paper presents a workflow that combines discrete and continuum descriptions that captures the salient features of the geological materials whilst also remaining numerically tractable. DFN models of fractured rock masses are typically developed using statistical distributions to generate realistic three-dimensional (3D) descriptions of the natural fracture network. Superimposed with this fracture description, is a matrix-orientated description based on an intact rock property model. Integration of these two descriptions into a single continuum rock mass description is achieved through a novel discrete-continuum upscaling process which combines fractures and intact properties into a unified form, providing effective mass permeability and geomechanical descriptions. The composite rock mass description is then carried forward into a numerically efficient multiphysics solver that provides effective simulation of both temperature and flow in a fully coupled manner to evaluate the performance potential of geothermal reservoir units. In addition, it will be demonstrated how the presented work can naturally embed within the stochastic framework of DFN and permit a probabilistic based evaluation. This paper presents application of the hybrid DFN-FV workflow for a hot sedimentary aquifer. The application is presented in terms of the characterization steps and a description of the input used, which is then supplemented with the dual fracture and matrix description. The demonstration will also touch on the efficient gridding of geological domains and provide example simulation results of multi-well injector and producer fluid flow and heat transfer. The work in this paper shows how the DFN-FV approach can be systematically employed to help with the success of geothermal well placement and completion studies in hot sedimentary aquifers.
- Geophysics > Seismic Surveying (0.68)
- Geophysics > Borehole Geophysics (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (0.47)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (3 more...)
A Sequentially Coupled THM Model for Fractured Enhanced Geothermal Systems using XFEM and Hybrid EDFM and MINC Models
Yu, Xiangyu (Colorado School of Mines) | Yan, Xia (China University of Petroleum, East China) | Wang, Cong (Saudi Aramco) | Wang, Shihao (Chevron N America Upstream) | Wu, Yu-Shu (Colorado School of Mines)
Abstract The long-term fluid circulation of Enhanced Geothermal Systems (EGS) involves complex coupled Thermal-Hydrological-Mechanical (THM) processes dominated by hydraulic and induced natural fractures. The hydraulic fracture of arbitrary shape in response to pressure changes and thermal strains can be handled by the three-dimensional (3D) eXtended Finite Element Method (XFEM). The induced/natural fractures are incorporated into the model and treated as one continuum of the Multiple INteracting Continua (MINC) for the investigation of their impacts. A TOUGH-code-based program, TOUGH2-EGS, is utilized to simulate the Thermal-Hydrological processes. The 3D Embedded Discrete Fracture Method (EDFM), compatible with the 3D XFEM, is adopted to model the hydraulic fracture. TOUGH2-EGS is then coupled with an XFEM simulator by the sequentially coupled fixed-stress split approach. The convergence performance of this coupling scheme is firstly analyzed by introducing the fracture stiffness coefficient into a single-fracture model. Sensitivity analyses are performed for this model in terms of injection temperature and thermal expansivity. The hybrid EDFM and MINC model is established and analyzed for an EGS with both hydraulic and induced/natural fractures. The convergence performance of the single-fracture model shows that an appropriate stiffness coefficient is essential for this model and different choices of the coefficient value result in distinct performances. The sensitivity analyses for injection temperatures and thermal expansivity are conducted by comparing effective stresses, pressure, temperature, and porosity/permeability distributions, as well as dynamic production temperature, outflow rate, and injection fracture permeability. The results illustrate that the fracture aperture is opened by the cold fluid injection and the reservoir is dominated by the thermal stress/strain. The temperature and pressure distribution are both affected by the thermal-hydrological-mechanical processes through the dynamic porosity, permeability, stress/strain, and fluid viscosity. The thermal breakthrough curves reflect that the conduction contributes the most to heating the fluid while the outflow rates demonstrate the mass loss due to the porosity/permeability altered by thermo-poro-elasticity. In the hybrid model, the enhancement of the natural fracture permeability notably delays the thermal breakthrough by allowing injected fluid to contact more hot reservoirs. Natural fracture spacing, MINC partition numbers are also varied to investigate their influence on the production behavior: the increased spacing delays the thermal breakthrough and needs more MINC partitions for modeling accuracy. Traditional coupled THM models are only applicable under the assumption of infinitesimal strains which does not hold in hydraulically fractured EGS reservoirs. The introduction of fracture stiffness stabilizes the numerical solution. The combined 3D XFEM and EDFM is capable of handling arbitrary fracture shapes in a 3D EGS model. Moreover, the hybrid hydraulic and induced/natural fracture model enables us to establish the stimulated reservoir volume of the EGS and investigate the operational and geological parameters.
- Energy > Renewable > Geothermal > Geothermal Resource (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource for Power Generation > Enhanced Geothermal System (0.61)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
Results from a Collaborative Industry Study on Parent/Child Interactions: Bakken, Permian Basin, and Montney
McClure, Mark (ResFrac Corporation) | Albrecht, Magdalene (SM Energy) | Bernet, Carl (Ovintiv) | Cipolla, Craig (Hess Corporation) | Etcheverry, Kenneth (Ovintiv) | Fowler, Garrett (ResFrac Corporation) | Fuhr, Aaron (SM Energy) | Gherabati, Amin (Ovintiv) | Johnston, Michelle (Arc Resources) | Kaufman, Peter (Hess Corporation) | MacKay, Mason (Arc Resources) | McKimmy, Michael (Birchcliff Energy) | Miranda, Carlos (Hess Corporation) | Molina, Claudia (Ovintiv) | Ponners, Christopher (ResFrac Corporation) | Ratcliff, Dave (ResFrac Corporation) | Rondon, Janz (ResFrac Corporation) | Singh, Ankush (ResFrac Corporation) | Sinha, Rohit (Marathon Oil) | Sung, Anthony (Marathon Oil) | Xu, Jian (Marathon Oil) | Yeo, John (Birchcliff Energy) | Zinselmeyer, Rob (Arc Resources)
Abstract This paper presents results from a collaborative industry study involving ten high-quality pad-scale datasets from the Delaware Basin, Midland Basin, Bakken, and Montney. The study had three primary goals: (a) compare/contrast observations between each dataset, (b) identify general strategies that can be used to mitigate parent/child impacts, and (c) provide concrete recommendations to optimize fracture design and well placement. For each dataset, an integrated hydraulic fracturing and reservoir simulation model was constructed and history matched to the observations. The models were calibrated to production data and pressure measurements, as well as to diagnostics such as: distributed acoustic sensing (DAS), microseismic, downhole imaging, chemical tracers, geochemical production allocations, and pressure observations from offset wells. History matching was performed by varying formation properties and model inputs to ensure consistency with the observations. Once the models were calibrated, the same set of approximately 120 sensitivity analysis simulations was performed on each model. Finally, an automated algorithm was used to quantitatively optimize fracture design and well placement to maximize economic performance. At each step in the process, the results were analyzed to identify the similarities and differences between the datasets and to explain why. The results show how differences in stratigraphy, well configuration, fracture design, and formation properties drive differences in parent/child phenomena. Optimal strategies to mitigate challenges depend on these site-specific conditions. Negative impacts from parent/child interactions cannot be entirely avoided. There is no strategy that can prevent the most important cause of child well underperformance – that wells are attempting to produce hydrocarbons from rock that has already been significantly depleted by parent well production. However, strategic design choices and quantitative economic optimization can significantly improve net present value and return on investment.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (35 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (8 more...)