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If least-squares linear regression is used to compute N in Step 5, an equation analogous to Eq. 17 is used (where Eow is substituted for Eowf). This solution method is iterative because the material-balance error must be minimized. This calculation is carried out with a trial-and-error method or a minimization algorithm. Least-squares linear regression and minimization algorithms have become standard features in commercial spreadsheets.
Wang, Wenguang (School of Geosciences, China University of Petroleum) | Lin, Chengyan (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum) | Lin, Jianli (School of Geosciences, China University of Petroleum) | Zhang, Xianguo (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum) | Dong, Chunmei (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum) | Ren, Lihua (School of Geosciences, China University of Petroleum / Geology Key Laboratory of Shandong Province / Key Laboratory of Deep Oil and Gas, China University of Petroleum)
The purpose of this paper is to use 3D compaction numerical simulation method to study the sandstone porosity evolution and high-value porosity area in the few well areas of offshore oilfields. These sandstones are located in the central inversion structural belt of the Xihu sag, East China Sea Basin. Based on geological data, seismic data, log data, thin section, scanning electron microscopy, cathode luminescence, bulk X-ray diffraction analysis, powder particle size analysis and routine core analysis, this study used compaction numerical simulation method to reconstruct the porosity evolution of different grain size sandstones in the fourth (H4) and fifth (H5) members of the Oligocene E3h Formation in the study area. Three aspects of research were carried out, including the distribution model of 3D grain size sandstones, mechanical compaction and chemical compaction parameters, 3D porosity evolution and high-value porosity areas. It was determined that there was no correlation between the porosity compaction loss and quartz cement content in different grain size sandstones in the H4 and H5 members, indicating that chemical compaction did not inhibit mechanical compaction. The mechanical compaction and chemical compaction were simulated separately. Different grain sizes sandstones had different mechanical compaction and chemical compaction porosity reductions. The porosity reductions of medium sandstone, sandy conglomerate and fine sandstone by mechanical compaction were 25.3%, 21.81% and 25.97%, and those by chemical compaction were 0.82%, 1.08% and 0.42%, respectively. The sandstone compaction stages of the H4 and H5 members under different tectonic stages were investigated. In the first phase of the slow subsidence stage, the reservoir temperature of the H4 and H5 members were less than 70°C, and these sandstones were in the stage of mechanical compaction. In the second phase of the slow subsidence stage, the reservoir temperature range of the H4 and H5 members were 70°C–114.63°C and 70°C–120.47°C, respectively; these sandstones entered the coexistence stage of mechanical compaction and chemical compaction. From the rapid subsidence stage to regional steady subsidence stage, the reservoirs temperature ranges of the H4 and H5 members were 114.63°C–159.7°C and 120.47°C–167.05°C, respectively; these sandstones were in the stage of chemical compaction dominated- mechanical compaction supplemented. Finally, the differences of sandstone compaction and porosity between the H4b-6 and H5-6 submembers and in the same layers were analyzed. By integrating sedimentary lithologies, porosity evolution, and reservoir "sweet spot" evaluation criteria, the spatial distribution of favorable areas in the H4b-6 and H5-6 submembers were determined. This study is of theoretical significance to elucidate the compaction characteristics, porosity evolution and high-value porosity area distribution in deep and ultra-deep clastic rocks, and also has reference value for the optimization of the tight sandstone favorable areas.
The Lower Tertiary play in the Gulf of Mexico (GoM) was identified and completion approaches were developed in the early 2000s to address the complexities of the formation. The use of single-trip multi-zone completion technology was identified as a cost-effective solution to the stacked pay and has been applied by many operators in the GoM (Clarkson et al. 2008, Burger et al. 2010, Grigsby et al. 2016). As these fields have matured, some operators have experienced formation pressure depletion in some of the pay intervals within the proposed completion, challenging this common completion method. The nature of a single-trip multi-zone completion dictates 1) all of the zones to be completed are perforated at the same time, and 2) the pressure gradients of these zones are similar enough that the well can be controlled by the well fluids. Early in the planning of this project, several of the zones within the pay interval of the target well were identified as depleted, which could result in fluid-loss-related control issues.
A porous media chemical delivery system has been developed which allows the release of various chemistries at a controlled rate, over long periods of time. This delivery system is able to replace a portion of the proppant used in gravel packing and fracturing, as well as an additive during acid stimulation. The placement of the delivery system in this manner allows for increased efficiency and elimination of operational issues associated with alternative treatments.
Several case histories are presented over multiple basins. These case histories outline the versatility of this chemical delivery system by highlighting its use in different environments. Successful deployment in a variety of fluid systems including seawater based cross-linked gel, slick water, and acid are also presented. Other design factors such as temperature, produced water salinity, scale type, stress on proppant, and produced water rate are discussed. The incorporation of all these factors has yielded design volumes varying from 0.5% to 40% of the proppant/gravel pack, depending on the inhibition duration (time / produced water volume) desired.
Results presented in this paper include successful scale inhibition for multiple years, include over 4 years with one application. Also highlighted are examples of inhibition in both conventional and unconventional reservoirs, as well as both onshore and offshore, and both North America and internationally.
This paper will be beneficial for production engineers who desire a cost effective solution to deploy production assurance chemicals in a one-time treatment resulting in a multi-year solution.
Microfiuidics and nanofiuidics have been used in the oil and gas industry for pore-scale research experiments and as application-specific tools (such as lab-on-a-chip PVT analyzers). The former technology constructs pore and pore-network proxies on compact lab-on-a-chip devices. Such proxies are then used to investigate the impact of specifically tuned geometric and/or material variable(s) on fluid transport via direct observation with microscopy. This paper reviews micro/nanofluidics findings by the authors and other geoscience and general porous-media researchers. Findings are related to the impacts of pore size, surface chemistry (wettability), fluid type and composition, and surface texture (roughness) on fluid transport variables, such as effective viscosity, imbibition, capillary trapping, adsorption, and diffusive processes. For example, the authors’ microfluidic findings include a critical surface roughness value beyond which capillary trapping during drainage increases drastically due to changes in subporescale flow regimes. The authors’ nanofluidic findings include that the fluid polarity and surface chemistry of a silica nanoconfinement can lead to additional contactline friction that causes significant deviations from the continuum Washburn equation for imbibition; these effects can potentially be incorporated in the quantitative analysis through an increased effective viscosity. Finally, this review highlights practical approaches for using labon-a-chip devices and their associated pore-scale findings as diagnostic tools to augment petrophysical laboratory measurements and guide field-scale pilot operations.
The Gulf of Mexico, and more precisely the Wilcox trend, has long been considered as challenging area for developing profitable hydrocarbon fields. In fact, the safe drilling of deep offshore wells needs to take into account the geological and geomechanical complexities, generated by the different sedimentological and tectonic events that accompanied the development of the Wilcox trend. In the case of Buckskin field, located in Keathley Canyon protraction (Figure 1), and in order to overcome those challenges, we developed a workflow that ranks all the parameters related to the geometry, the geology, the rock quality and the geomechanics characteristics of the reservoir. The core of the workflow is articulated around a probabilistic method that will assess the uncertainty of the productivity index, based on experimental design and Monte Carlo simulation. The proposed workflow allowed the optimization of the PI of the well thanks to a highly deviated reservoir section at a depth below 24,000', combined with an optimal fracking job.
Colombia’s New Ambitions Include Caribbean and Shale Development, But Are They Achievable? You have access to this full article to experience the outstanding content available to SPE members and JPT subscribers. To ensure continued access to JPT's content, please Sign In, JOIN SPE, or Subscribe to JPT At some point during the first half of this year, Colombia replaced politically and economically crippled Venezuela as Latin America’s third-largest oil-producing country. Since Brazil ended state-owned Petrobras’ monopoly and opened up its industry to international companies in the late 1990s, the country’s oil output has almost tripled as it found and tapped into its giant offshore presalt fields. Output from Mexico’s state-owned Pemex, meanwhile, has fallen to its lowest level since at least 1990, and President Andrés Manuel López Obrador is working to stymie energy reforms implemented in 2013 to rejuvenate industry in the country.
Mejia, Lucas (The University of Texas at Austin) | Mehmani, Ayaz (The University of Texas at Austin) | Balhoff, Matthew (The University of Texas at Austin) | Torres-Verdin, Carlos (The University of Texas at Austin)
We employ microfluidics to capture the impact of several diagenetic processes, including the formation of vugs and fractures, cementation, and grain dissolution, on waterflooding sweep efficiency in diagenetically altered media. Heterogeneous porous media are constructed with glass micromodels using micro-CT images of sandstones in order to mimic chemical and mechanical diagenetic processes typically encountered in subsurface rocks. Cementation was emulated by placing micrograins in intergranular pores, dissolution was introduced by replacing stress-bearing grains with arrays of micrograins, a vug was incorporated into the pore system by removing grains from a circular area in the middle of the matrix domain, and a high-permeability channel was added to study the effect of a natural fracture on flow efficiency.
From the five cases studied, we find porosity-forming processes such as those giving rise to vugs, natural fractures, and grain dissolution, result in the largest increases in recovery efficiency. Secondary pores enhance the merging of fingering dendrites, which results in higher recovery. In addition, the increase in local hydraulic conductivity due to porosity-forming diagenesis directs the fingering dendrites to traverse the middle of the matrix in addition to its boundaries. Modifying the geometry of micromodels according to probable burial stages (paragenesis), allows us to investigate the effect that subsurface conditions have on microscopic sweep and enables a quantitative interdisciplinary method for reducing reservoir development uncertainties.
Pore-scale investigations can reveal dominant underlying fluid flow mechanisms for predicting the sweep efficiency of waterflooding in porous media. In pore-scale numerical modeling, the rock pore space is discretized via meshing or represented by an approximate pore-network depending on the domain size and available computational resources. Core-flood experiments are conducted by imposing a flow rate (or pressure gradient) on the porous medium and measuring the fluid volumes at the outlet. To evaluate microscopic sweep in core floods, pore-scale images of floods performed in small cores can be acquired using fast synchrotron imaging. However, both numerical modeling and core flooding become intractable in tight rocks1 due to resolution limitations for capturing the pore space in representative domain sizes (Bultreys et al., 2016). Microfluidics experiments have the unique ability to provide controlled environments for displacement experiments, including displacement of oil by waterflooding, in short time spans (minutes to hours). In addition, microfluidics devices allow direct visualization of flow and transport at the pore scale, which provides insight for engineering more effective recovery methods for subsequent experiments.
Digital rock physics (DRP), via both direct numerical simulation and pore-network modeling, holds great promise in terms of probing such pore-scale controls on transport, particularly with multiphase flow and sensitivity analysis of time-intensive measurements such as relative permeability. However, despite advances in micro-computed tomography (microCT) and scanning electron microscopy (SEM) techniques, obtaining cost-effective representative elementary volumes (REV) at sufficient resolution that capture dual-scale porosity and surface textures remains a formidable challenge in establishing digital rock physics as a predictive toolset. Furthermore, implementers are faced with several options of numerical solvers such as finite element modeling, lattice Boltzmann method, and mass balance-based pore-network modeling. This paper reviews the current status of establishing an REV and upscaling techniques for DRP in tight and/or diagenetically-altered rocks, highlighting successful and unsuccessful pore-to-core data benchmarking examples by the authors and the greater literature in terms of static and dynamic properties.
The review finds that performing DRP on a single image modality is not sufficient, even for many conventional rocks, and that it is crucial to interface with experimental data, be it core analysis deliverables or subpore-scale and Darcy-scale microfluidics. In unconventional rocks, the majority of work does not leverage mesoscale simulations, instead zooming in to a discrete pore-scale scenario that is often not benchmarked with SCAL data. Even when a simulation domain is benchmarked, the matching of a discrete case with a multivariable situation is non-unique. Benchmarking with dynamic or pseudo-dynamic core data such as MICP and single phase permeability will greatly help reduce variables. Finally, this paper offers a technical roadmap for the robust application of unconventional DRP for the petrophysics and general subsurface community.
Rock diagenesis can generate complex pore-lining and pore-filling textures beyond the idealized sedimentary “spherical grain pack” that greatly influence pore size distributions and transport properties including permeability, capillary trapping, diffusion, and relative permeability. Compaction, cementation, dissolution, and microporosity are examples of such geometric complexity. Meanwhile, mineralogical composition and organic matter content can lead to multiple surfaces of potentially varying wettability. Petrophysically-speaking, dispersed shale, laminated shale, and structural shale grains are categories of complexity as well. These various configurations often necessitate the need for visualization of rock pore systems, a practice that has been done for years via thin section and SEM imaging as well as computed tomography. Traditionally, imaging techniques have been used for validation of a model or assumption (such as laminated sands in shaly sand analysis), but, as computing power and microscopy technologies have increased, many researchers and vendors have leveraged these technologies to create digital laboratories where petrophysical properties can be directly calculated. This intriguing field of study is called digital rock physics (DRP) and is a potential addition to the petrophysical toolkit.
Microfluidics and nanofluidics have been used in the oil and gas industry pore-scale research experiments and as application-specific tools (such as lab-on-a-chip PVT analyzers). The former technology constructs pore and/or pore network proxies on compact lab-on-a-chip devices and investigates the impact of specifically tuned geometric and or material variable(s) on fluid transport via direct observation with microscopy. This paper reviews micro/nanofluidics findings by the authors and other geoscience and general porous media researchers related to the impacts of pore size, surface chemistry (wettability), fluid type and composition, and surface texture (roughness) on fluid transport variables such as effective viscosity, imbibition, capillary trapping, adsorption, and diffusive processes. For example, the authors’ microfluidic findings include the presence of a critical surface roughness value beyond which capillary trapping during imbibition increases drastically due to changes in subpore-scale flow regimes. The authors’ nanofluidic findings in silica nanochannels include that the polarity of a fluid and the surface chemistry of a nanoconfinement can lead to an additional contact line friction that causes significant deviations from the continuum Washburn equation for imbibition; these effects can potentially be incorporated through an increased effective viscosity. Finally, this review highlights practical approaches for utilizing lab-on-a-chip devices and their associated pore-scale findings as diagnostic tools to augment petrophysical lab measurements and guide field-scale pilot operations.
Predicting multiphase flow dynamics in subsurface formations requires understanding fluid behavior in length scales spanning from subpore1 to field. The formation of tight rocks is preceded by a myriad of mechanical and chemical reactions from weathering during sediment deposition, to bioturbation, pressure dissolution at high temperature and pressures, and authigenic clay growth after burial. The resultant pore space morphological and topological complexities as well as nontrivial surface chemistry properties can cause many of the traditional petrophysical flow models, which are typically described in core-scale, such as Carman-Kozeny for absolute permeability or Brooks-Corey for relative permeability, to be erroneous (Byrnes et al., 2008; Mousavi and Bryant, 2012).