The present study provides a comprehensive set of new analytical expressions to help understand and quantify well interference due to competition for flow space between the hydraulic fractures of parent and child wells. Determination of the optimum fracture spacing is a key factor to improve the economic performance of unconventional oil and gas resources developed with multi-well pads. Analytical and numerical model results are combined in our study to identify, analyze, and visualize the streamline patterns near hydraulic fractures, using physical parameters that control the flow process, such as matrix permeability, hydraulic fracture dimensions and assuming infinite fracture conductivity. The algorithms provided can quantify the effect of changes in fracture spacing on the production performance of both parent and child wells. All results are based on benchmarked analytical methods which allow for fast computation, making use of Excel-based spreadsheets and Matlab-coded scripts. Such practical tools can support petroleum engineers in the planning of field development operations. The theory is presented with examples of its practical application using field data from parent and child wells in the Eagle Ford shale (Brazos County, East Texas). Based on our improved understanding of the mechanism and intensity of production interference, the fracture spacing (this study) and inter-well spacing (companion study) of multifractured horizontal laterals can be optimized to effectively stimulate the reservoir volume to increase the overall recovery factor and improve the economic performance of unconventional oil and gas properties.
The reporting of potential resources is essential to assess the future development plan and profitability of a petroleum discovery, but if the project is under appraised and production data are absent, analysts often use analogs for preliminary estimates of technically recoverable volumes. To address this, a workflow is presented for selecting appropriate analogs for unconventional plays and using them to estimate the target play's potential. The proposed technique is demonstrated with a case study of the as-yet undeveloped Bowland Shale, which is the most prominent of the shale plays in the United Kingdom (UK) and is at the early stage of its assessment. The paper describes the current shale gas activity in the UK, highlighting the enviromental constraints placed on would-be Bowland Shale developers, which impact on drilling and production operations and stem from the geographic proximity of urban developments, infrastructure and nature, which limit the size of well pad footprint in the UK where land use is high. Studies have estimated the play's in-place resources for possible future development, but there are few estimates of its corresponding recoverable volumes due to lack of production history. At the outset, a database is created with published minimum-average-maximum ranges of key parameters such as total organic carbon, maturity level, gas filled porosity, permeability, etc. that play a major role in resources estimation and recovery potential for all unconventional plays. A comparison of triangular distributions, key parameter by key parameter, between the target shale play and the analog database, is then carried out using novel graphical and statistical methods to establish a "confidence factor" relating to the analog's viability. The most appropriate analog for the Bowland Shale is chosen from an exhaustive list of North American shale gas plays. Analytical approaches are then used to transform a model of the published type well performance of the selected analog by exchanging key model parameters with those of the target shale play. The paper shows how UK operational constraints can be statistically incorporated into the workflow and have a marked effect on the estimated recovery from the Bowland Shale.
Analytically-derived criteria are presented for the orientation of fracture initiation from horizontal wellbores drilled in porous-permeable (poroelastic) media. This involves drilling-induced tensile fractures (DITFs) from non-perforated wellbores and completion-induced hydraulic fractures (CIHFs) from perforated wellbores with cylindrical perforation geometry. The criteria are developed considering the tangential stresses on two points (extremes) around the base of the perforation; one for the initiation of longitudinal fractures and another for the initiation of transverse fractures, with respect to the wellbore. In-situ stress state, wellbore pressure, and the formation's mechanical and poroelastic properties are independent variables that are shown to control the orientation of the initiated hydraulic fractures; the dependent variable.
The DITF orientation can be used to constrain the magnitude of the maximum horizontal stress; the most difficult aspect of the in-situ stress tensor to constrain. Transverse CIHF initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal initiation occurs at comparatively higher wellbore pressures. However, transverse CIHF initiation occurs more frequently than transverse DITFs, because the presence of perforations aids transverse fracture initiation. The region of the in-situ stress states where transverse initiation is promoted is shown in dimensionless plots for perforated and non-perforated wellbores. Fracture initiation criteria for specific cases presented can be used to predict the orientation of fracture initiation in oilfield operations.
The orientation of CIHFs controls the productivity of hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Fracture initiation often follows a plane different to the final fracture propagation plane. Stress re-orientation in the near-wellbore region may promote fracture initiation of different orientation than the orientation dictated by the far-field stresses. The range of in-situ stress states in which transverse fracture initiation is promoted increases as Biot's poroelastic coefficient,
Zeng, Jie (The University of Western Australia) | Li, Wai (The University of Western Australia) | Liu, Jishan (The University of Western Australia) | Leong, Yee-Kwong (The University of Western Australia) | Elsworth, Derek (The Pennsylvania State University) | Tian, Jianwei (The University of Western Australia) | Guo, Jianchun (Southwest Petroleum University)
After performing hydraulic fracturing treatments in shale reservoirs, the hydraulic fractures and their adjacent reservoir rocks can be damaged. Typically, the following fracture damage scenarios may occur: (1) choked fractures with near-wellbore damage; (2) partially propped fractures with unpropped or poorly propped sections within the fractures; (3) fracture face damage; and (4) multiple damage cases. The basic equations of fracture skin factors, which are widely used to depict fracture damage, are derived under steady-state conditions. They are not accurate when the damaged length is relatively long and are not applicable for multiple fracture damage and partially propped fractures. In this paper, a new composite linear flow model is established considering all above-mentioned fracture damage mechanisms, complex gas transport mechanisms, and the stimulated reservoir volume (SRV) of shale gas reservoirs.
The matrix model is modified from de Swaan-O's spherical element model considering the slip flow, Knudsen diffusion, surface diffusion, and desorption. Natural fractures are idealized as a thin layer that evenly covers the matrix. The reservoir-fracture flow model is extended from the seven-region linear flow model with four additional sub-regions to handle single and multiple fracture damage mechanisms. Specifically, the inner reservoir region near the primary hydraulic fracture is treated as the SRV where the secondary fracture permeability is higher than that of other unstimulated dual-porosity regions and obeys a power-law decreasing trend due to the attenuate stimulation intensity within the SRV. The flows in different regions are coupled through flux and pressure continuity conditions at their interfaces.
This model is validated by matching with the Marcellus Shale production data. And the degraded model's calculation matches well with that of the seven-region linear flow model validated by KAPPA software. Type curves with five typical flow regimes are generated and sensitivity analyses are conducted. Results indicate that the presence of the SRV diminishes pressure and derivative values in certain flow regimes depending on the SRV properties. Fracture face damage, choked fracture damage, and partially propped fractures all control specific flow regimes but the fracture face damage shows the smallest influence, only dominating the late fracture linear flow regime and the matrix-fracture transient regime. In the multiple fracture damage case, some typical flow regimes can be easily identified except the partially propped fractures. The field application example further ensures the applicability in dealing with real field data.
Penghui, Su (PetroChina Research Institute of Petroleum Explorationand and Development) | Zhaohui, Xia (PetroChina Research Institute of Petroleum Explorationand and Development) | Ping, Wang (PetroChina Research Institute of Petroleum Explorationand and Development) | Liangchao, Qu (PetroChina Research Institute of Petroleum Explorationand and Development) | xiangwen, Kong (PetroChina Research Institute of Petroleum Explorationand and Development) | Wenguang, Zhao (PetroChina Research Institute of Petroleum Explorationand and Development)
Interest has spread to potential unconventional shale reservoirs in the last decades, and they have become an increasingly important source of hydrocarbon. Importantly, pore structure of shale has considerable effects on the storage, seepage and output of the fluids in shale reservoirs so that reliable fractal characteristics are essential. To better understand the evolution characteristics of pore structure for a shale gas condensate reservoir and their influence on liquid hydrocarbon occurrences and reservoir physical properties, we conducted high-pressure mercury intrusion tests (HPMIs), field emission scanning electron microscopies (FESEM), total organic carbon (TOC), Rock-Eval pyrolysis and saturation measurements on samples from the Duvernay formation. Furthermore, the fractal theory is applied to calculate the fractal dimension of the capillary pressure curves, and three fractal dimensions D1, D2 and D3 are obtained. The relationships among the characteristics of the Duvernay shale (TOC, organic matter maturity, fluid saturation), the pore structure parameters (permeability, porosity, median pore size), and the fractal dimensions were investigated.
The results show that the fractal dimension D1 ranges from 2.44 to 2.85, D2 ranges from 2.09 to 2.15 and D3 ranges from 2.35 to 2.48. D2 and D3 have a good positive correlation. The pore system studied mainly consists of organic pores and microfractures, with the percentage of micropores being 50.38%. TOC has a positive relationship with porosity and D3 due to the development of organic pores. D3 has a positive correlation with gas saturation. With increased D3, median pore size shows a decreasing trend and an increase in permeability and porosity, demonstrating that D3 has a large effect on pore size distribution and the heterogeneity of pore size. In general, D3 has a better correlation with petrophysical and petrochemical parameters. Fractal theory can be applied to better understand the pore evolution, pore size distribution and fluid storage capacity of shale reservoirs.
A marked change from a decade ago, Appalachia, the Permian, and the Haynesville now represent almost half of total US gas production, EIA reports. BP To Buy US Shale Assets From BHP for $10.5 Billion BP ends a year of speculation as to who will buy BHP Billiton’s much-coveted US unconventional business, transforming its Lower 48 portfolio in the process. Drilling and completion expenditure and activity is projected to show multiyear double-digit growth from 2018–2022 despite a flattening of rig count increases. After a drop in drilling activity in recent years, the Haynesville shale has become a hot area for natural gas production in the US, and companies are looking to bolster their positions in the area. In drawdown management, operators can exert control over the downhole flow pressure, reservoir pressure, and choke size to avoid estimated ultimate recovery (EUR) losses.
A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. After a drop in drilling activity in recent years, the Haynesville shale has become a hot area for natural gas production in the US, and companies are looking to bolster their positions in the area. Top US seismic experts say they are keeping a watchful eye on ground shaking in the state as new concerns are raised in neighboring Texas.
In the shale oil business, cash flow is a life or death issue. For smaller players, money from investors and lenders is getting harder to find. Keen on Anadarko for a while, Occidental Petroleum is ready to do battle with Chevron for the big independent. What Happened to the Private, Family-Owned Oil Company? When the oil and gas industry goes one way, family-owned Hunt Oil goes the other.