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Nicholson, A. Kirby (Pressure Diagnostics Ltd.) | Bachman, Robert C. (Pressure Diagnostics Ltd.) | Scherz, R. Yvonne (Endeavor Energy Resources) | Hawkes, Robert V. (Cordax Evaluation Technologies Inc.)
Abstract Pressure and stage volume are the least expensive and most readily available data for diagnostic analysis of hydraulic fracturing operations. Case history data from the Midland Basin is used to demonstrate how high-quality, time-synchronized pressure measurements at a treatment and an offsetting shut-in producing well can provide the necessary input to calculate fracture geometries at both wells and estimate perforation cluster efficiency at the treatment well. No special wellbore monitoring equipment is required. In summary, the methods outlined in this paper quantifies fracture geometries as compared to the more general observations of Daneshy (2020) and Haustveit et al. (2020). Pressures collected in Diagnostic Fracture Injection Tests (DFITs), select toe-stage full-scale fracture treatments, and offset observation wells are used to demonstrate a simple workflow. The pressure data combined with Volume to First Response (Vfr) at the observation well is used to create a geometry model of fracture length, width, and height estimates at the treatment well as illustrated in Figure 1. The producing fracture length of the observation well is also determined. Pressure Transient Analysis (PTA) techniques, a Perkins-Kern-Nordgren (PKN) fracture propagation model and offset well Fracture Driven Interaction (FDI) pressures are used to quantify hydraulic fracture dimensions. The PTA-derived Farfield Fracture Extension Pressure, FFEP, concept was introduced in Nicholson et al. (2019) and is summarized in Appendix B of this paper. FFEP replaces Instantaneous Shut-In Pressure, ISIP, for use in net pressure calculations. FFEP is determined and utilized in both DFITs and full-scale fracture inter-stage fall-off data. The use of the Primary Pressure Derivative (PPD) to accurately identify FFEP simplifies and speeds up the analysis, allowing for real time treatment decisions. This new technique is called Rapid-PTA. Additionally, the plotted shape and gradient of the observation-well pressure response can identify whether FDI's are hydraulic or poroelastic before a fracture stage is completed and may be used to change stage volume on the fly. Figure 1: Fracture Geometry Model with FDI Pressure Matching Case studies are presented showing the full workflow required to generate the fracture geometry model. The component inputs for the model are presented including a toe-stage DFIT, inter-stage pressure fall-off, and the FDI pressure build-up. We discuss how to optimize these hydraulic fractures in hindsight (look-back) and what might have been done in real time during the completion operations given this workflow and field-ready advanced data-handling capability. Hydraulic fracturing operations can be optimized in real time using new Rapid-PTA techniques for high quality pressure data collected on treating and observation wells. This process opens the door for more advanced geometry modeling and for rapid design changes to save costs and improve well productivity and ultimate recovery.
Abstract Most waterfloods in California target sandstone formations that are unconsolidated in nature with high porosities and high permeabilities. These formations are also characterized by high Poisson ratios and low values of Young's Moduli. There has been a concern if, during the waterfloods of these types of formations, fracturing takes place at high-injection gradients. The influence of various factors on leak-off is studied in detail, indicating that with an increase in rock permeability, the leak-off velocity increases. This study included a comprehensive analysis of the characteristics of such soft formations and their responses to high injection gradients. We show that if the leak-off factors are adjusted to reflect high permeability and proper geomechanical properties, the probability of fracture formation is nil at injection gradients up to 0.9 psi/ft, for unconsolidated rooks. We computed estimated fracture width, fracture height, fracture length and noted for all three calculations, it takes gradients approaching 1psi/ft to note a non-trivial estimated value for these characteristics. This study shows that for unconsolidated formations like those in California targeted for waterfloods, the probability of fracture formation under pressure gradients of 0.9 psi/ft. is nil, and high injectivities can be exercised without the fear of fracture formation.
Summary Alternate or out-of-sequence fracturing (OOSF) has been field tested in western Siberia in 2014 and in western Canada in 2017, 2018, and 2019, with operational success and positive well-production performance. It is conducted by fracturing Stage 1 (at the toe) and then fracturing Stage 3 (toward the heel), followed by tripping back to place Stage 2 (center fracture) between Stages 1 and 3 (outside fractures). During placing the center fracture, OOSF can exploit the reduced stress anisotropy to effectively activate the planes of weakness (natural fractures, fissures, faults, and joints) to potentially create failure surfaces with different breakdown angles in virtually all directions. This can potentially lead to branch fractures that can connect the hydraulic fractures to stress-relief fractures that are created while placing the outside fractures, ultimately generating a complex fracture network and enhancing fracture connectivity. Despite prior works on fracture modeling (calibrated by field tests) and geomechanical modeling, a comparative analysis of wellbore-breakdown character and hydraulic-fracture orientation during OOSF is still lacking. Thus, in this study, the solutions to 3D Kirsch equations are provided for both low and high stress anisotropies to analyze the differences in breakdown gradient, failure angle, and fracture orientation under various geomechanical and treatment-design conditions. The consideration is given to an intact rock from an isotropic stress state to high-stress-anisotropy conditions. The results are analyzed in the context of the downhole-measured pressures and temperatures. The results indicate that the reduced stress anisotropy during OOSF leads to favorable treating conditions: With a net fracture-extension pressure greater than the reduced stress anisotropy, fracture complexity can be created by allowing the fracture to grow with different failure angles. Also, a well can be drilled and fractured at any inclination or azimuth with favorable breakdown gradients of 45 to 85% of the overburden gradient. The reduced stress anisotropy can also trigger some challenges. The near-well stress-concentration effects can become more pronounced, promoting longitudinal fracture creation. For treatments with tortuosity greater than the stress anisotropy, longitudinal fractures can be created instead of transverse fractures because the tortuosity is transmitted to the wellbore body and not into the fractures. In this case, to initiate transverse fractures, either the wellbore must intersect the pre-existing transverse notches or the near-well pore-fluid pressure must exceed the axial stress and rock strength (before the hoop stress reaches the tensile failure point). In addition, the fracture might lose directional control and follow any path of weakness. Hence, the rock-fabric effects become more dominant under a low-stress-anisotropy regime, which means that with no pre-existing transverse natural fractures or notches, a longitudinal fracture can be generated at the bottom and top of an intact horizontal wellbore. This is the first attempt in identifying the circumstances that should be avoided for optimizing OOSF through geomechanical modeling and the analysis of the downhole-measured pressures and temperatures to reveal the differences in breakdown character using the Kirsch equations under various geomechanical and treatment conditions during the low-stress-anisotropy regime.
The second fundamental idea in thermodynamics is the total entropy balance or the "second law" of thermodynamics. Entropy is a thermodynamic property that expresses the unidirectional nature of a process and, in some sense, is "nature's clock." For example, a cup of hot coffee at room temperature cools down instead of heating up. Conservation of total mass and energy are insufficient to solve many phase-equilibrium problems. Processes that satisfy these conservation equations may not be physically possible; that is, the process of a cold cup of coffee spontaneously heating up on your dinner table would satisfy the first law of thermodynamics but has a near zero probability to occur.
Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of 10 md from well-developed cleat systems. Southwest of the fairway, Fruitland coals are typically 20 to 40 ft thick and are considerably underpressured with vertical pressure gradients in some areas of less than 0.20 psi/ft.
To evaluate a given casing design, a set of loads is necessary. Casing loads result from running the casing, cementing the casing, subsequent drilling operations, production and well workover operations. External pressure loads are produced by cement and fluids outside the casing, which can be modeled by pressure distributions. Pressure distributions are typically used to model the external pressures in cemented intervals. These pressure distributions are discussed next.
Chen, Qing (Schlumberger) | Kristensen, Morten (Schlumberger) | Johansen, Yngve Bolstad (Aker BP) | Achourov, Vladislav (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Downhole fluid analysis (DFA) is one pillar of reservoir fluid geodynamics (RFG). DFA measurements provide both vertical and lateral fluid gradient data. These gradients, especially the asphaltene gradient derived from accurate optical density (OD) measurements, are critical in thermodynamic analysis to assess equilibration level and identify RFG processes. Recently, an RFG study was conducted using DFA and laboratory data from an oil field in the Norwegian North Sea. Fluid OD gradients show equilibrated asphaltenes in most of the reservoir, with a lateral variation of 20%. This indicates connectivity, which is confirmed by three years of production data. Two outliers are off the asphaltene equilibrium curve implying isolated sections, one each on the extreme east and west flank. Their asphaltene fraction varies by a factor of six. Such a difference reveals that different charge fluids entered the reservoir, and the equilibrated asphaltenes are the result of an after-charge mixing process. Meanwhile, different gas-oil contacts (GOCs) exist in the reservoir, indicating a lateral solution-gas gradient. Geochemistry analysis shows the same level of mild biodegradation in all the fluid samples, including those from two isolated sections. This means that biodegraded oil spills into the whole reservoir with little or no in-reservoir biodegradation. Furthermore, lateral asphaltene gradients at different times after charge have been preserved; it was a factor of six in asphaltenes content initially and is now 20% in the present day. This unique data set provides a valuable constraint to simulate reservoir fluid after-charge mixing processes to present day, aiming to investigate the factors impacting the evolution of lateral composition gradients in geologic time in a connected reservoir. Numerical simulations were performed over geologic time in reservoirs filled by oil with a lateral density gradient, which imitates the lateral compositional gradients in the gas-oil ratio (GOR) and asphaltenes measured in the above oil field. Simulations show that this lateral gradient creates lateral differential pressures and causes a countercurrent fluid flow forming a convection cell. In reservoirs with realistic vertical-to-horizontal aspect ratios, such fluid flows are not rapid, and lateral gradients can be partially retained in moderate geologic times. Additionally, diffusion was included in the simulation. The reservoir model was initialized with two GOCs producing subtle lateral GOR and density gradients. The simulated mixing process transports gas from higher GOR regions to lower GOR regions and reduces the GOC difference. However, the flux of solution gas transport is small. Consequently, we conclude that lateral GOR and asphaltene gradients can persist for moderate geologic time, which is consistent with observation from the field.
Nuclear magnetic resonance (NMR) has been, and continues to be, widely used in chemistry, physics, and biomedicine and, more recently, in clinical diagnosis for imaging the internal structure of the human body. The same physical principles involved in clinical imaging also apply to imaging any fluid-saturated porous media, including reservoir rocks. The petroleum industry quickly adapted this technology to petrophysical laboratory research and subsequently developed downhole logging tools for in-situ reservoir evaluation. NMR logging, a subcategory of electromagnetic logging, measures the induced magnet moment of hydrogen nuclei (protons) contained within the fluid-filled pore space of porous media (reservoir rocks). Unlike conventional logging measurements (e.g., acoustic, density, neutron, and resistivity), which respond to both the rock matrix and fluid properties and are strongly dependent on mineralogy, NMR-logging measurements respond to the presence of hydrogen protons.
In the evaluation of reservoir rock formations, the geology and geophysics team always considers the depositional setting and post-deposition alteration. Any suggestion to ignore the post-deposition alterations of rock formations in reservoir evaluation would be met with disbelief and incredulity. Figure 1 shows different deposition settings (turbidites, carbonate platforms, injectites, and deltaic alluvia fans), as well as various post-deposition processes and structures (faulting, halokinesis, anticlines and karsts). For sedimentary rock, post deposition alteration is called structural geodynamics from which all structural traps result. No geologist would ever employ the deficient workflow of solely considering the depositional setting but not the post-deposition alteration when trying to decipher reservoirs.