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.
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. For example, the relative permeability that increases in the direction of increasing oil saturation must be the oil relative permeability. The endpoints of the relative permeabilities in Figs. 1 and 2 are defined by the critical gas saturation Sgc and the residual oil saturation Sor. Common names and symbols for some saturation endpoints are listed in Table 1.
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.
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,
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. 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.
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.
Distributed Acoustic Sensing (DAS), as a seismic sensor, has unique features allowing us to record multiple datasets with variable acquisition parameters set inside the recording box, while using one continuous recording cable and a single round of shooting. We reveal how these distinct features allow DAS to deliver multi-scale data and have the capability to focus on both the near surface and deeper targets simultaneously. We present synthetic and field examples of "deep" and "shallow" DAS surveys and demonstrate their effectiveness. The new capabilities of surface seismic with DAS technology comprise a sensing revolution that addresses long-standing near-surface issues in land seismic without compromising the deeper imaging. Achieving similar capabilities with point sensors could be done but would lead to ballooning acquisition costs, whereas surface seismic with DAS can deliver them at a cost less than conventional geophone acquisition available today.
Smith, Robert (Geophysics Technology, EXPEC Advanced Research Center, Saudi Aramco) | Bakulin, Andrey (Geophysics Technology, EXPEC Advanced Research Center, Saudi Aramco) | Silvestrov, Ilya (Geophysics Technology, EXPEC Advanced Research Center, Saudi Aramco)
Accurate near-surface velocity models are required to correct for shallow velocity heterogeneities that can otherwise lead to the misinterpretation of seismic data, particularly in the case of low-relief structures. Here we show how a novel uphole acquisition system utilizing distributed acoustic sensing (DAS) technology can be used in a number of different ways to generate near-surface models.
The novel smart DAS uphole system connects multiple shallow wells with one continuous optical fiber. The horizontal and vertical segments of the fiber allow several techniques for near-surface model building to be tested using the same system. Uphole surveys use the vertical fiber segments to make accurate, localized velocity measurements, while the directivity of the DAS fiber enables horizontal sections to be used for refraction tomography and surface-wave inversion.
The smart DAS uphole acquisition system, which enables the collection of data for deep reflection imaging and near-surface characterization simultaneously, has been successfully tested for the first time. Data acquired from ten smart DAS upholes produced excellent early arrival waveform quality for picking and subsequent velocity model building. This direct velocity measurement of the near-surface can reduce uncertainty in the seismic interpretation. In addition, replacing the shallow part of the depth velocity model with the DAS uphole model resulted in significant improvements in the final depth image from topography.
The directivity of DAS enables the recording of refracted events on horizontal fiber sections which have been picked as input to refraction tomography. This produces an alternative near-surface model that captures a larger volume of the subsurface. Ultimately, while the uphole velocity model is only suitable for removing long-wavelength components of near-surface variation, the refraction velocity model may allow for the correction of small-to-medium wavelength statics.
Global natural gas consumption is projected to grow from 112 Tcf to 163 Tcf in the next 20 years representing an increase rate of nearly 2% annually; this implies not only enormous investment, but also new challenges and search for geoscientists and petroleum professionals with expertise in this new fields. Shales are the most abundant sedimentary rocks in sedimentary basins of the earth; but, small portion of them would achieve commercial productivity. This course will train the attendees on the evaluation methods and techniques that can be utilized to delineate productive shales from barren shales. One of the major challenges of gas shale reservoirs is to apply conventional log data to acquire reservoir rock properties. In this course log analysis for gas shale reservoirs will be demonstrated practically to estimate reservoir properties.