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Accurate prediction of fracture initiation pressure and orientation is paramount to the design of a hydraulic fracture stimulation treatment and is a major factor in the treatment’s eventual success. In this study, closed-form analytical approximations of the fracturing stresses are used to develop orientation criteria for fracture initiation from perforated wells relative-to-the-wellbore (longitudinal or transverse). These criteria were numerically assessed and found to overvalue transverse fracture initiation, which takes place under a narrow range of conditions when the rock formation’s tensile strength is lower than a critical value and the breakdown pressure falls within a "window."
A robust three-dimensional numerical model is used to evaluate solutions for the longitudinal and transverse fracturing stresses for a variable wellbore pressure, hence numerically-deriving correction factors for the closed-form approximations. Geomechanical inputs from the Barnett Shale in Texas are considered for a horizontal well aligned parallel to the direction of the least compressive horizontal principal stress. The numerically-corrected expressions can predict fracture initiation pressures for a specific orientation of fracture initiation (longitudinal or transverse). Similarly, at known breakdown pressures, the corrected expressions are used to predict the orientation of fracture initiation. Besides wellbore trajectory, the results depend on the perforation direction. For the Barnett Shale case study (normal faulting regime), perforations on the side of the borehole yield both a wider breakdown pressure window and a higher critical tensile strength by 32.5%, compared to perforations on top of the borehole. Leakage of fracturing fluid around the wellbore reduces the breakdown pressure window by 11% and the critical tensile strength by 65%.
Dimensionless plots are employed to present the range of
During loss of well control events, fracture initiation occurring during the post-blowout capping stage following uncontrolled discharge, can lead to reservoir fluids broaching to the seafloor. A classic example is Union Oil's 1969 oil spill in Santa Barbara channel, where fracture initiation at various locations caused thousands of gallons per hour to broach in the ocean floor over a period of a month before it could be controlled (Mullineaux, 1970; Easton, 1972). The impacts on California's oil industry are still felt strongly today. Disasters as such could be prevented if the effects of the post-blowout loss of well control stages (uncontrolled discharge and capping) are incorporated into the shut-n procedures and the wellbore architecture. Analytical models are used to simulate the loads on the wellbore in the different stages during loss of control and predict capping pressure buildup during the shut-in to indicate fracture initiation during the capping stage. Using these models, critical capping pressure and subsequently critical discharge flowrates is calculated for a well below which fracture initiation would occur. A hypothetical case study with typical deepwater Gulf of Mexico parameters is performed demonstrating the likelihood of fracture initiation during different discharge flowrates, discharge periods and shut-in methods (abrupt/"hard" or multistage/"soft").
Asala, Hope I. (Louisiana State University) | Chebeir, Jorge A. (Louisiana State University) | Manee, Vidhyadhar (Louisiana State University) | Gupta, Ipsita (Louisiana State University) | Dahi-Taleghani, Arash (Pennsylvania State University) | Romagnoli, Jose A. (Louisiana State University)
The unsteady recovery of oil and gas prices in early 2017 led to an increase in drilling and hydraulic-fracturing operations in liquid-rich shale plays in North America. As field-development strategies continue to evolve, refracturing and infill-well drilling must be carefully combined to optimize shale-project profitability. Moreover, operators must bear in mind the undulating natural-gas demands persisting in an oversupplied shale-gas environment. In this paper, we use data-driven approaches to predict successful refracturing candidates and local gas demand for the second-tier optimization of a shale-gas supply-chain network.
A strategic-planning (SP) model is developed for optimizing the net present value (NPV) of a case-study shale-gas network in the Marcellus Play. This SP model uses a mixed-integer-nonlinear-programming (MINLP) formulation developed in the General Algebraic Modeling System (GAMS, Release 220.127.116.119). This model relies directly on input from reservoir simulation, local-gas-demand forecast, water-availability forecast, and natural-gas and West Texas Intermediate (WTI) crude-oil price forecasts.
Before reservoir simulation, machine learning (ML) is used to predict successful refracturing candidates, using a feed-forward neural network (NN), random-forest (RF) classifier, and a t-distributed stochastic-neighbor-embedding (t-SNE) visualization technique. Using the obtained results, best-practice field-development strategies are implemented in the area of interest (AOI) using reservoir simulation. Local gas demand is forecasted using a long-short-term-memory (LSTM) recurrent NN (RNN) that uses a multivariate data set created from local and global variables affecting shale-gas demand. A water-management structure is also developed for the optimization framework.
Using a 300-well data set (with 17 input features), successful refracturing candidates were proposed according to the joint outcome of an optimal 17/23/128/2 feed-forward NN, a t-SNE plot, and a techno-economic review. After ranking F1 scores, the developed NN outperforms the RF and support-vector-machine (SVM) algorithms for frac/refrac-well classification. The developed 32/256/128/120 LSTM model showed at least a 93% (+/-1%) prediction performance using three or five input features. The results illustrate the ability of the developed LSTM model to accurately predict local gas demands during periods of high or low gas demand.
After SP optimization over a 10-year planning horizon, the economic results indicate an NPV of USD 481.945 million, using the proposed physics-data-driven-based approach. An NPV of USD 611.22 million is obtained when no ML was used. The results reveal that the application of ML to strategic planning can prevent erroneous feedback of project profitability while allowing early-time decision making that maximizes shale-asset NPV.
Supporting Information included as a separate document below.
Analytically-developed criteria are presented for the orientation of fracture initiation from horizontal wellbores drilled in porous-permeable (poroelastic) media, considering fluid infiltration. This involves drilling-induced tensile fractures (DITFs) from non-perforated wellbores and completion-induced hydraulic fractures (CIHFs) from perforated wellbores with cylindrical perforation geometry. Transverse CIHF initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal initiation occurs at comparatively higher wellbore pressures. Nevertheless, transverse CIHF initiation occurs more frequently than transverse DITFs, because of the presence of perforation tunnels, which aid transverse fracture initiation.
Unlike for DITFs, the complex geometry of a perforated wellbore does not allow derivation of expressions for the exact solutions of the stresses inducing longitudinal and transverse fracture initiation. Thus, approximations implemented in the past for perforated wells in linearly-elastic media are extended to poroelastic media, deriving closed-form analytical solutions for the fracturing stresses to develop an orientation criterion for fracture initiation from perforated wellbores. This is useful for completion engineers; when targeting low permeability formations, wellbores must be made to induce multiple transverse fractures, as opposed to longitudinal fractures, which are more effective in higher permeability formations.
The region of the
Meddaugh, William Scott (Chevron ETC) | Osterloh, W. Terry (Chevron Corp.) | Gupta, Ipsita (Chevron Corp.) | Champenoy, Nicole (Chevron Corporation) | Rowan, Dana E. (Chevron) | Toomey, Niall (Chevron) | Aziz, Shamsul (Chevron Corp.) | Hoadley, Steve Floyd (Chevron Corp.) | Brown, Joel (Chevron Energy Technology Company) | Al-Yami, Falah (Chevron Corp.)
The Paleocene/Eocene First Eocene dolomite reservoir is a candidate for continuous steamflooding due to its large resource base and low estimated primary recovery. There are two steamflood pilot projects in operation to evaluate reservoir response to steam injection: a single pattern pilot (SST) and a 40-acre, 16 pattern pilot (LSP). At the SST an interval with abundant tidal flat cycle caps characterized by muddy, finely crystalline dolomites with low porosity and permeability may be the observed vertical barrier to steam migration. Detailed studies, including micropermeameter measurements and micro-CT scans were used to characterize the heterogeneity. Data suggest that similar vertical barriers may exist at the LSP. Early steamflooding results show a positive response to injection and multiple thermal events (likely baffles rather than barriers). The data also shows the occurrence and distribution of some lateral high permeability pathways between injectors and producers as well as between producers. While the rapid temperature response observed in a few wells may reflect fractures or karst-like zones, simulation using very fine grids shows that some wells will experience very short breakthrough times without fracture or karst-like zones.
Injection of high temperature, high pH fluids may induce fluid/rock interactions that affect reservoir fluid flow near-well and in-depth. This in turn could affect storage capacity, production and injectivity. Reactive transport models (2D-RTM) were run to simulate high pH steam injection into the First Eocene reservoir for a continuous injection period of 6-12 months to understand possible changes in mineralogy, coupled with porosity change and potential scaling. Initial results predict precipitation of calcite and brucite, dissolution of dolomite and anhydrite, and conversion of gypsum to anhydrite. Sensitivity studies examined the impact of steam quality, pH, rock surface area, reaction rates, and mineralogy.