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Treatment evaluation leads to problem identification and to continuously improved treatments. The prime source of information on which to build an evaluation are the acid treatment report and the pressure and rate data during injection and falloff. Proper execution, quality control, and record keeping are prerequisites to the task of accurate evaluation. Evaluation of unsatisfactory treatments is essential to recommending changes in chemicals and/or treating techniques and procedures that will provide the best treatment for acidizing wells in the future. The most important measure of the treatment is the productivity of the well after treatment.
The design of a waterflood has many phases. First, simple engineering evaluation techniques are used to determine whether the reservoir meets the minimum technical and economic criteria for a successful waterflood. If so, then more-detailed technical calculations are made. These include the full range of engineering and geoscience studies. The geologists must develop as complete an understanding as possible of the internal character of the pay intervals and of the continuity of nonpay intervals.
Hybrid steam/solvent processes have gained importance as a thermal-recovery process for heavy oils in recent years. Among the identified physical mechanisms that play a role during these processes are heat-transfer phenomena, gravity drainage and viscous flow, solvent mass transfer, and mass-diffusion/-dispersion phenomena. In this paper, a study of sensitivity to grid size is described. Ideally, this work will provide some insight into methodological aspects to be considered when hybrid steam/solvent processes are modeled. Recent studies concerning the size of the liquid-solvent-rich zone where molecular diffusion and dispersion occur have implied that a detailed representation of the solvent/steam-chamber edge is necessary in the numerical model.
Summary Since its discovery in 1971, numerous matrix stimulations have been performed in South Pars field. However, there are still various challenges surrounding stimulation job design and evaluation methods. To tackle these issues, 16 matrix operations were selected to be analyzed from different phases of the development project of the reservoir. The objective of this study is to introduce an efficient interpretation method to determine optimum treatment volume (gal/ft), compare the effectiveness of diverters, calculate stimulation ratio (SR), and forecast post-acid production behavior from surface treatingdata. The modified inverse injectivity (Iinv) method, which is fully discussed by Safari et al. (2020), is used in this study. The obtained data were analyzed in terms of Iinv decreasing trend, Iinv humps, and pre-/post-acid Iinv during the stimulation process. In addition, pre-/post-stimulation surface testing data are gathered and analyzed. These data are coupled with post-acid Iinv to find a correlation to predict production behavior of treated wells. SR is defined as the ratio of pre-acid Iinv to post-acid Iinv of a treated well. Finally, SR values are validated with available production logging tool (PLT) data from two stimulation operations. First, the obtained results indicated that optimum treatment volume (gal/ft) of acid depends on well conditions. It means that wells with high initial formation damage require more volumes of stimulation fluids. In this regard, wells treated with 27/27 gal/ft treatment volume design [27 gal/ft 28% hydrochloric acid (HCl) and 27 gal/ft 15% viscoelastic surfactant (VES)] were understimulated. Although treatment volume design of 53/53 gal/ft seems to be adequate for low-skin wells, higher treatment volume (gal/ft) would further enhance productivity of highly damaged wells. This result was confirmed by stimulation of a damaged well with treatment volume of 60/60 gal/ft. Finally, the most reliable design applied in the field so far is the 70/70 gal/ft treatment volume. Second, Iinv analyses depicted that better diversion is observed in wells with lower injectivity and higher damage. At the next step, the calculated SR values showed an average deviation of less than 10% from downhole PLT data. Ultimately, the produced results demonstrated that there is a direct relation between the post-acid Iinv and surface drawdown in this field. Therefore, production behavior of treated wells can be correlated by having access to post-acid Iinv. The novelty of this work pertains to use of surface treating data recorded during a stimulation operation to generate Iinv and its associated analysis curves to evaluate performance of matrix stimulation operations. By applying this method, optimum volume of acid and diverter, diversion effectiveness, SR, and an estimation of post-acid surface drawdown can be obtained from the simple surface treating data. The secondary-produced data could lead to a better understanding of carbonate reservoir behavior during matrix stimulations such as in the South Pars field.
The variable data quality of core analysis, the sensitivity of results to different test methods, poor reporting standards, and the reluctance of some vendors to share experience and expertise have contributed to basic mistakes and poor data quality. In many cases, an inconsistent or inappropriate approach to the design, management, and interpretation of the core-analysis program has been adopted and exacerbated by the conflicting requests from the end users. A core-analysis-management road map was designed to increase the value from core-analysis investments by enabling a more-proactive, more-coherent, and more-consistent approach to program design and data acquisition. In hydrocarbons-in-place and core analysis, the volume of stock-tank oil initially in place in a reservoir can be calculated. The gross rock volume and gross factor in the net-/gross-pay ratio are the primary responsibilities of geophysicists and geologists.
In this paper, the authors consider the effect of water chemistry on water/rock interactions during seawater and smart waterflooding of reservoir sandstone cores containing heavy oil. Oil recovery, surface-reactivity tests, and multicomponent reactive-transport simulation were conducted to understand smart waterflooding better. The authors determine that lowering magnesium-ion (Mg2) concentration results in lower additional oil recovery, and that lowering calcium-ion (Ca2) concentration leads to higher additional oil recovery. "Smart water" (SW) can be defined as a water engineered by manipulating the ionic composition (adding or removing ions) regardless of the resulting salinity. An upward pH shift has been reported in the literature during low-salinity (LS) and/or smart waterflooding.
Produced-water reinjection (PWRI) is an important strategy for deriving value from waste water, but its implementation can face challenges related to injectivity and safety issues. The first objective of a PWRI-design study is to supply water-quality specifications, and the second is to supply injection-pressure specifications. The objective of this paper is to detail how water quality and injection pressure are deduced when uncertainties of input data are considered. Before any PWRI design commences, a feasibility study is performed to assess any compatibility issues and evaluate the risk of scaling and souring and the viability of the project. Bacteria growth and corrosion of the installations have to be tackled and mitigated upstream in the early phase of the project.
Fakher, Sherif (Missouri University of Science and Technology) | El-Tonbary, Ahmed (American University in Cairo) | Abdelaal, Hesham (University of Lisbon) | Elgahawy, Youssef (University of Calgary) | Imqam, Abdulmohsin (Missouri University of Science and Technology)
Abstract Unconventional shale reservoirs have become and large unconventional supplier of oil and gas especially in North America. They are usually produced from using hydraulic fracturing which produces and average of 7-10% per well. This research studies the application of carbon dioxide (CO2) enhanced oil recovery (EOR) in shale reservoirs to increase oil recovery to more than 20%. Cyclic CO2 injection was used to conduct all experiments rather than flooding. The main difference between both procedures and the advantage of cyclic injection over flooding in shale reservoirs is explained. A specially designed vessel was constructed and used to mimic the cyclic CO2 injection procedure. The effect of CO2 soaking pressure, CO2 soaking time, and number of soaking cycles on oil recovery was investigated. Results showed that cyclic CO2 injection can increase oil recovery substantially, however there are some points that must be taken into consideration including optimum soaking pressure and time in order to avoid a waste of time and capital with no significant increase in oil recovery. This research not only provides an experimentally backed conclusion on the ability of cyclic CO2 injection to increase oil recovery from shale reservoirs, it also points to some major issue that should be considered when applying this EOR method in unconventional shale in order to optimize the overall procedure.
Summary In the process of shale coring, the gas adsorption will increase the flow resistance of gas inside the core, which will inevitably affect the accuracy of shale gas loss. To clarify the underlying effects of seepage flow and related factors during shale desorption, we conducted an experimental study on the influence of methane on seepage resistance of fractured shale and matrix shale under different adsorption pressures. Changes in reservoir fluid and deformation resulting from CH4 saturation adsorption resulted in changes in shale permeability. This study investigated six adsorption durations (2, 4, 6, 12, 18, and 24 hours) under adsorption pressures of 5, 9, and 13 MPa in shale samples. During each cycle, different injection pressures (2 to 6 MPa) were applied, and seepage resistance of shale samples was measured by the transient method. The results showed that the permeation resistance of the sample decreased significantly after adsorption of CH4 reached saturation and decreased with increasing CH4 adsorption duration. Compared with matrix shale samples, fractured shale samples were shown to have more suitable pore microcracks and higher CH4 affinity. Therefore, fractured samples were found to have higher permeability resistance and higher adsorption capacity compared to matrix shale. The permeability flow of a sample had a negative exponential relationship with confining pressure, and stress sensitivity increased with increasing CH4 adsorption time. The model representing gas loss indicated a positive correlation between change in impermeability and the flow of escaped gas on the core surface. A significant reduction in the impermeability of the core will result in a significant reduction in shale gas loss.
Abstract The Greater Enfield Project (GEP) is a challenging offshore oil development, designed to produce from the Laverda Canyon, Cimatti and Norton over Laverda oil fields. Six water injection wells are required to provide pressure support and sweep oil to three production wells in the Laverda Canyon and Cimatti oil accumulations to improve oil recovery. The GEP injection wells are a critical aspect of water flood design in a complex field, new to Woodside and with limited global benchmarks. A specific drilling and completion fluid system (Reservoir drilling fluid, completion fluid and chemical filter cake breaker) combined with a unique clean up and displacement technique have been adopted to provide high and sustainable matrix injection performance. While filter cake breakers have been previously used in the industry, they are typically combined with a flowback for filter cake removals. Filter cake clean up by means of flowback was discounted for GEP due to cost and the inability of some wells to naturally flow during early life. All GEP injection wells were completed in 2018-2019, one of which is globally the longest horizontal water injection well completed to date based on the Rushmore data base. Fieldwide injection commenced in July 2019 with favorable results. This paper summarises the key design aspects adopted to deliver successful matrix injection performance, presents the improvements implemented during offshore execution and provides an insight into the early life injection performance.