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Abstract The reduction of pore pressure during reservoir production alters the initial stress state within the reservoir and the surrounding rocks. This stress variation is responsible for many problems encountered during production (e.g. fault reactivation, casing deformation). In this investigation, a newly designed True Triaxial Stress Loading and Pore Pressure Applying Apparatus (TTSL-PPAA) was applied to study the coupling of pore pressure drawdown and reservoir stress changes under actual field conditions. The objective was to overcome the shortcomings of commonly employed depletion testing under conventional triaxial conditions, which assumes that both horizontal stress components are equal. The depletion simulations were performed by decreasing the pore pressure and under applying constant vertical and keeping zero horizontal strains, i.e. uniaxial strain boundary conditions. The results showed that both horizontal stresses decrease with a linear trend with pore pressure depletion. The reduction rates of minimum and maximum horizontal stresses, however, are not uniform. The rate of maximum horizontal stress reduction is higher than the minimum horizontal stress component. Moreover, the pore pressure/stress coupling intensity is dependent on the initial, pre-production, stress state. By increasing the initial vertical stress, and therefore, decreasing the ratios of horizontal to vertical stress, (referred to as K H = σ H /σ V and K h = σ h /σ V), the effect of pore pressure depletion on in situ stress components was decreased. The obtained test results imply that, in addition to stress magnitude changes, the stress regime might be locally changed by production due to pore pressure/stress coupling. Furthermore, the rock sample failure in some depletion tests indicates that the pore pressure/stress coupling can be used to describe the production induced seismicity reported in hydrocarbon reservoirs worldwide. Highlights • The paper describes the development of a new True Triaxial Stress Loading and Pore Pressure Applying Apparatus (TTSL-PPAA). • The TTSL-PPAA system is employed to demonstrate the depletion mechanisms associate with oil reservoirs. • The depletion simulations were conducted to show the coupled nature of pore pressure and in situ stress filed. • Due to pore pressure reduction both horizontal stress components start to decrease in a linear trend. [ABSTRACT FROM AUTHOR]

Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks. Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery. [ABSTRACT FROM AUTHOR]

Three rounds of exploration in Marsel, Kazakhstan show that the area has good petroleum geological conditions; however, the exploration degree is low and the resource potential is unclear. The total organic carbon ( TOC ) content is the criteria for effective source rocks and is also the key parameter to calculate the amount of resources; while previous evaluations of the effective source rocks and calculated amounts of resources were based on residual TOC , which gradually decreases with mass hydrocarbon expulsion; therefore, this will inevitably produce errors. For greater accuracy, the TOC recovery coefficient formula was used to recover the residual TOC in Marsel; then, the criteria of the effective source rocks were revised to calculate the Carboniferous and Devonian resources in Marsel. The results are as follows: for the source rocks in Marsel, the TOC recovery coefficient of the Carboniferous source rocks is approximately 1.6, while that for the Devonian is approximately 2.0; the revised lower limit of TOC for the effective source rocks is 0.3% and 0.25% for the Carboniferous and Devonian, respectively; after TOC recovery, the total amount of hydrocarbon expulsion is 26.7 × 10 12 m 3 , the total amount of recoverable resources is 2.62–5.10 × 10 12 m 3 , and the mean is 3.79 × 10 12 m 3 for the main source rocks. The effective source rocks evaluated based on the recovered TOC and the latter resources could reflect the quantity of source rocks and actual resource potential of Marsel more accurately. This has certain significance for the exploration of areas that have low levels of exploration with an unclear understanding of the resource potential as well as a high degree of thermal evolution and a low quantity of residual TOC . [ABSTRACT FROM AUTHOR]

Abstract: This article introduces a methodology for integrating geochemical data in reservoir simulations to improve hydrocarbon reservoir models. The method exploits routine measurements of naturally existing inorganic ion concentration in hydrocarbon reservoir production wells, and uses the ions as non-partitioning water tracers. The methodology is demonstrated on a North Sea field case, using the field''s reservoir model, together with geochemical information (SO4 2−, Mg2+, K+, Ba2+, Sr2+, Ca2+ and Cl− concentrations) from the field''s producers. Based on the dataset, some of the ions are shown to behave almost as ideal seawater tracers, i.e. without sorption to the matrix, ion exchange with the matrix or scale formation with other ions in the formation water. Moreover, the dataset shows that ion concentrations in pure formation water vary according to formation. This information can be used to allocate produced water to specific water-producing zones in commingled production. Based on an evaluation of the available data, one inorganic component, SO4 2−, is used as a natural seawater tracer. Introducing SO4 2− as a natural tracer in a tracer simulation has revealed a potential for improvements of the reservoir model. By tracking the injected seawater it was possible to identify underestimated fault lengths in the reservoir model. The demonstration confirms that geochemical data are valuable additional information for reservoir characterization, and shows that integration of geochemical data into reservoir simulation procedures can improve reservoir simulation models. [Copyright &y& Elsevier]