The orientation of hydraulic fractures controls the productivity from hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Analytical approximations from the literature for the longitudinal and transverse fracturing stresses are modified to incorporate pore pressure effects and then used to develop a criterion for the orientation of fractures initiating from perforated wells. The validity of this criterion is assessed numerically and is found to overestimate transverse fracture initiation, which occurs under a narrow range of conditions; when the formation tensile strength is below a critical value and the breakdown pressure within a "window."
In horizontal wells, it is easier to achieve longitudinal fracture initiation, as transverse fracture initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal fracture initiation occurs at comparatively higher wellbore pressures. The numerical study shows that in contradiction with existing analytical approximations, the tangential stress which induces transverse fracture initiation, is a stronger function of wellbore pressure just as the stress inducing longitudinal fracture initiation is. This reduces the breakdown pressure window for transverse fracture initiation compared to what the derived analytical approximations predict. Furthermore, this creates an additional constraint for transverse fracture initiation; the critical tensile strength value, which determines the maximum tensile strength for which transverse fracture initiation is possible for a given stress state.
The range of the
Africa (Sub-Sahara) An 816-mile 2D seismic acquisition program was completed on the Ampasindava block, located in the Majunga deepwater basin offshore northwest Madagascar. The data will provide improved subsurface imaging of the large Sifaka prospect and will potentially mature additional prospects in the Ampasindava block to drill-ready status. Sterling Energy (UK) holds a 30% interest in the Ampasindava production sharing contract, which is operated by ExxonMobil Exploration and Production (Northern Madagascar) (70%). Asia Pacific Production began on the Liuhua 19-5 gas field in the Pearl River Mouth basin in the South China Sea. The field is expected to hit peak production of 29 MMcf/D this year. China National Offshore Oil Corporation (100%) is the operator. Drilling began on the YNG 3264 and the CHK 1177 development wells onshore in Myanmar.
Africa (Sub-Sahara) Eni finished a production test on its Minsala Marine 1 NFW well, located in Marine XII block, 35 km offshore The Republic of the Congo. During the test, the well delivered natural flow in excess of 5,000 B/D of 41 API crude and 14 MMcf/D of natural gas from a 37-m opened section of the discovery's 420-m column. Eni (65%) is operator, with state-owned partner SNPC (25%), and New Age (African Global Energy) Limited (10%). Asia Pacific CNOOC started natural gas production from the Panyu 34-1/35-1/35-2 project at the Pearl River Mouth basin in the South China Sea. Main production facilities for the three gas fields include one comprehensive platform, two sets of underwater production systems, and 13 producing wells. Two wells are producing a total of 21 MMcf/D of gas. The project is expected to reach peak production of 150 MMcf/D.
Africa (Sub-Sahara) Aminex Petroleum Egypt (APE), a subsidiary of UK-based Aminex, discovered oil at its South Malak-2 (SM2) well on the West Esh el Mellaha-2 concession in Egypt. Tests showed flow rates of approximately 430 B/D of 40 API gravity crude oil. Based on the findings at SM2, a full field development program will be presented to the Egyptian authorities and the joint venture partners before commercial development. APE is the operator of the license with partner Groundstar Resources. Foxtrot International discovered oil and gas at its Marlin North-1 well in Block CI-27, offshore Cote d'Ivoire. A 22-m perforated section of a gas-bearing column in a Turonian interval flowed at a stabilized rate of 25 MMcf/D of gas and 150 B/D of condensate through a 46/64-in.
Africa (Sub-Sahara) Bowleven has started drilling operations at the Moambe exploration well on the Bomono permit in Cameroon. Moambe is the second well in a two-well program, approximately 2 km east of the first well, Zingana. It targets a previously undrilled Paleocene Tertiary three-way dip fault block containing multiple sands and will be drilled to an estimated 1620 m in measured depth. Both wells will be logged. Bowleven is the operator and holds 100% interest. Asia Pacific Murphy Oil discovered gas at its Permai exploration well in deepwater Block H in the South China Sea offshore Malaysia. The find is Murphy's eighth consecutive success in the area around the Rotan floating liquefied natural gas project, which is planned to begin its first production in 2018.
Relative permeability and capillary pressure defines relative permeabilities as dimensionless functions of saturation with values generally ranging between 0 and 1. Relative permeability is important for estimating the flow of reservoir fluids. The semilog scale of Figure 1 is convenient for reading the relative permeabilities less than 0.05. Although the curves are labeled "gas" and "oil" in these figures, the phase identity of a curve can be deduced without the labels. For example, the relative permeability that increases in the direction of increasing oil saturation must be the oil relative permeability.
Water is the wetting phase. Figure 1.5 – Primary drainage, imbibition, and secondary drainage for an oil/water system in which the oil and water wet the solid surface equally. Figure 1.6 – Primary drainage and imbibition for unconsolidated dolomite powder (the lines merely connect the data). These authors wrote capillary pressure as the negative of Eq. 4 because oil was the wetting phase for most of the tests. The legend gives contact angles measured through the water phase (in degrees). Leverett and coworkers, based on the evaluation of gas/water capillary pressure data for drainage and imbibition in unconsolidated sands, proposed the following definition: ....................(15.6) The function j(Sw), defined in Eq. 15.6, is known to many as the "Leverett j-function." The j-function is obtained from experimental data by plotting against Sw. The combination is often considered an estimate of the mean hydraulic radius of pore throats.
The East Duvernay shale basin is the newest addition to the list of prolific reservoirs in Western Canada. Over the last 3 years, horizontal drilling and multistage hydraulic fracturing have increased significantly. Because much of the play is still relatively new, much of the drilling has been limited to single wells or two wells per pad. Due to the low permeability of the matrix, hydraulic fracturing is required to unlock the full potential of the East Duvernay field. Because geomechanics is a critical factor in determining the effectiveness of hydraulic fracture propagation, we examined how varying the pore pressure profiles affects modeled in situ stresses, hydraulic fracture geometries, and overall field optimization.
The pore pressure varies across the East Duvernay shale basin with the depth of the reservoir and other geomechanical parameters. The stresses in the Ireton, Upper Duvernay, Lower Duvernay, and Cooking Lake reservoirs also varies from the West to the East shale basins. High-tier logging, core measurements, and field data were used to build a mechanical earth model, which is then input for hydraulic fracture simulations. Whole core images and image logs indicate the Duvernay to be a naturally fractured reservoir. Because pore pressure is a direct input into the interpretation for in situ stresses, we sensitized on seven pore pressure profiles through the Ireton, Upper and Lower Duvernay, and Cooking Lake reservoirs. Typical pumping design currently being implemented in the Upper Duvernay was used to determine hydraulic fracture geometry based on the various in situ stress profiles. Black oil PVT models were built to run numerical reservoir simulation production forecasts to understand the effect of variations in geomechanical properties on well production performance. The effect of the varying hydraulic fracture properties on well spacing was also investigated for the seven pore pressure profiles, by combining the complex hydraulic fracturing and reservoir simulation.
The results clearly indicated the need to better understand, quantify, and constrain the in situ stress profiles variations with changes in pore pressure models. Hydraulic fracture length is greater within the Upper Duvernay when a constant pore pressure is modeled in the Ireton, Duvernay and the Cooking Lake, which leads to an overestimation of production. If a normal pore pressure is modeled in the Ireton with overpressure in the Duvernay, the hydraulic fracture grows into the Ireton and gives a more realistic production forecast. When the modeled pore pressure is gradually ramped up from the Lower Ireton into the Duvernay, slightly greater fracture length is created in the Duvernay but not enough to make a huge difference in forecasted production. These varying results for the modeled hydraulic fracture geometries impact the optimum number of wells per section.
As more wells come on production and the economic viability of the play is proven, operators will drill more wells per section. Thoroughly understanding the variations in geomechanics across the formations above and below the Duvernay is important. This objective of this study was to drive the conversation about the data that need to be collected and tests that should be run to support the optimization of economic development of the play for years to come.
Binder, Gary (Colorado School of Mines) | Titov, Aleksei (Colorado School of Mines) | Tamayo, Diana (Colorado School of Mines) | Simmons, James (Colorado School of Mines) | Tura, Ali (Colorado School of Mines) | Byerley, Grant (Apache Corporation) | Monk, David (Apache Corporation)
In 2017, distributed acoustic sensing (DAS) technology was deployed in a horizontal well to conduct a time-lapse vertical seismic profiling (VSP) survey before and after each of 78 hydraulic fracturing stages. The goal of the survey was to more continuously monitor the evolution of stimulated rock throughout the treatment of the well. From two vibroseis source locations at the surface, time shifts of P-waves were observed along the well that decayed almost completely by the end of the treatment. A shadowing effect in the time shifts was observed that enables the height of the stimulated rock volume to be estimated. Using full wavefield modeling, the distribution of time shifts is well described by an equivalent medium model of vertical fractures that close as pressure declines due to fluid leak-off. Converted P to S waves were also observed to scatter off stimulated rock near some stages as confirmed with full wavefield modeling. The signal-to-noise ratio is a limitation of the current dataset, but recent improvements in DAS technology can enable stage-by-stage monitoring of the stimulated rock height, fracture compliance, and decay time as a well is completed.
Distributed Acoustic Sensing (DAS) has opened new possibilities for seismic monitoring of unconventional reservoirs. Using a laser interrogator to launch light pulses down a fiber optic cable, dynamic strain changes can be sampled along the cable from the phase shift of light backscattered to the interrogator (Hartog, 2017). Since the fiber optic cable can be permanently cemented outside the casing in a borehole, highly repeatable vertical seismic profiling (VSP) surveys can be acquired frequently without costly wireline geophone deployments that interfere with well treatment activities (Mateeva et al., 2017; Meek et al., 2017).
As described by Byerley et al., 2018, a unique interstage DAS VSP survey was conducted in 2017 during the stimulation of a horizontal well targeting the Wolfcamp formation in the Midland Basin, Texas. Using two vibroseis source locations offset about 1 mile from the heel and toe of the well, DAS data was acquired in the treatment well before and after each of 78 hydraulic fracturing stages. At the expense of fewer source locations, this type of acquisition allows the evolution of the stimulated rock volume (SRV) to be monitored on a stage-by-stage basis as the well is treated.
The SWP project is located in a mature waterflood undergoing conversion to CO2-WAG operations at Farnsworth, Texas, USA. Utilized CO2 is anthropogenic, sourced from a fertilizer and an ethanol plant. Major project goals are optimizing the storage/production balance, ensuring storage permanence, and developing best practices for CCUS.
This paper provides a review of work performed toward development of a 3D coupled Mechanical Earth Model (MEM) for use in assessment of caprock integrity, fault reactivation potential, and evaluation of stress dependent permeability in reservoir forecasting. Mechanical property estimates computed from geophysical logs at selected wellbores were integrated with 3D seismic elastic inversion products to create a 3D "static" mechanical property model sharing the same geological framework as the existing reservoir simulation model including 3 major faults. Stresses in the MEM were initialized from wellbore stress estimates and reservoir simulation pore pressures. One way and two way coupled simulations were performed using a compositional hydrodynamic flow model and geomechanical solvers.
Coupled simulations were performed on history matched primary, secondary (waterflood), and tertiary (CO2 WAG) recovery periods, as well as an optimized WAG prediction period. These simulations suggest that the field has been operating at conditions which are not conducive to either caprock failure or fault reactivation. Two way coupled simulations were performed in which permeability was periodically updated as a function of volumetric strain using the Kozeny-Carmen porosity-permeability relationship. These simulations illustrate the importance of frequent permeability updating when recovery scenarios result in large pressure changes such as in field re-pressurization through waterflood after a long primary depletion recovery period. Conversely, production forecasting results are less sensitive to permeability update frequency when pressure cycles are short and shallow as in WAG cycles.
This paper describes initial work on development of a mechanical earth model for use in assessment of geomechanical risks associated with CCUS operations at FWU. The emphasis of this work is on integration of available geomechanical data for creation of the static mechanical property model. Preliminary coupled hydro-mechanical simulations are presented to illustrate some of the key diagnostic output from coupled simulations which will be used in later work for in depth evaluation of specific risk factors such as induced seismicity and caprock integrity.