Decrease In Reservoir Pressure Research Articles

ИССЛЕДОВАНИЕ И АНАЛИЗ МЕТОДОВ ОПРЕДЕЛЕНИЯ ЭФФЕКТИВНОСТИ ПРИМЕНЕНИЯ ТЕХНОЛОГИИ ПРОПАНТНОГО ГИДРОРАЗРЫВА ПЛАСТА

Актуальность. Большинство месторождений ООО «ЛУКОЙЛ-ПЕРМЬ» находятся на завершающей стадии разработки, и на них выполняется большое количество операций гидроразрыва пласта (ГРП). В условиях высокой выработки запасов, обводнения скважин и снижения пластового давления необходимо планировать проведение ГРП на тех скважинах, где может быть получен максимальный прирост дебитов нефти. Цель: разработка методики прогноза дебитов нефти с использованием вероятностно-статистических методов. Объекты: данные по использованию пропантного ГРП на карбонатном В3В4 объекте Батырбайского месторождения. Методы: анализ данных по оценке эффективности ГРП с помощью использования вероятностно-статистических методов. Результаты. С использованием вероятностно-статистического метода построены многомерные математические модели оценки эффективности ГРП, которые позволили определить приросты дебитов нефти. Одним из основных преимуществ вероятностно-статистического метода является то, что все используемые для прогноза показатели, имеющие различные размерности, были переведены в безразмерные величины, что упрощает сопоставительный анализ. Кроме этого, выполнено сравнение полученных приростов дебитов нефти с методом расчета дебита жидкости через удельный коэффициент продуктивности. Выполненный анализ показал, что разработанный вероятностно-статистический метод прогноза обеспечивает более точную сходимость с фактическими данными по приростам дебитов нефти, в отличие от результатов, полученных по методу удельного коэффициента продуктивности. Значения коэффициентов парной корреляции для вероятностно-статистического метода составили по объекту разработки В3В4 – 0,85, тогда как по методу удельной продуктивности, соответственно, – 0,15, что на статистическом уровне подтверждает более высокую эффективность предлагаемого метода.

Physicochemical models of effusive rhyolitic eruptions constrained with InSAR and DEM data: A case study of the 2011-2012 Cordón Caulle eruption

The 9 month long 2011-2012 eruption of Cordón Caulle (Southern Andes, Chile) is the best instrumentally recorded rhyolitic eruption to date and the first time that the effusion of a rhyolitic flow has been observed in detail. We use Interferometric Synthetic Aperture Radar (InSAR), with time-lapse digital elevation models (DEMs) and numerical models to study the dynamics of coupled magma reservoir deflation and lava effusion. InSAR recorded 2.2-2.5 m of subsidence after the first three days of the eruption, which can be modeled using a spheroidal magma reservoir at a depth of ∼5 km, ∼20 km long, and with a pressure drop of 20-30 MPa. The source is elongated in the NW-SE direction and its large dimensions imply a large plumbing system active throughout the eruption and spanning neighboring volcanoes, with a slight change in the geometry halfway through the effusive phase. TanDEM-X and Pléiades DEMs record the extrusion of both the rhyolitic lava flow and the intrusion of a shallow laccolith around the eruptive vent after the third day of the eruption, with a total volume of ∼1.45 km3 DRE. The laccolith was emplaced during the first month of the eruption, during both the explosive and effusive stages of the eruption. Both the reservoir pressure drop and the extruded volume time series follow quasi-exponential trends, and can be explained by a model that couples the reservoir pressure decrease, time- and pressure-dependent variations in the magma properties inside of the reservoir, and conduit flow. This model predicts both the temporal evolution and amplitude of both time series during the effusive phase, and a magma compressibility of ∼10−10 Pa−1, half the reported compressibility of the magma of the sub-Plinian explosive phase. Further, we estimate that the reservoir contained 1-3 wt.% dissolved H2O at the onset of lava effusion, with no exsolved CO2 and H2O in the reservoir throughout the effusive phase. This implies that the magma was significantly degassed after the explosive phase. The remaining volatiles in the magma after the explosive stage might have caused magma fragmentation, consistent with the hybrid explosive-effusive style observed during the waning of the eruption.

ANALYSIS OF THE REASONS FOR FAILURES OF THE DRIVE OF THE BOREHOLDER RODS

Currently, the operation of oil deposits in Western Siberia is characterized by a decrease in the amount of oil produced, a decrease in reservoir pressure and fluid flow to the well. The large depth of the pump descent while simultaneously increasing the curvature of the wellbore and the angle of inclination of the wellbore in the process of raising the fluid with a high content of mechanical impurities significantly increases the load on the elements of the well pumping unit. The failure rate of installations is determined by a combination of technological factors influencing the frequency of failures of the pumping unit. The results of the operation of low-yield wells by sucker-rod pumping units in the conditions of oil fields in Western Siberia are analyzed. To assess the impact of technological factors on the accident rate of pumping machines, a regression analysis of data on their failures was carried out. According to the results of the regression analysis, the interdependence of the water content in the well production (water cut), the loads on the polished rod string and the failure rate of the drive of the well pump is found. It has been established that the main share of failures is made by the failures of the pumping unit, including the transmission, gearbox and crank mechanism. One of the unfavorable factors in the operation of the pumping unit is the unevenness of the force on the balancer head in the process of moving the polished rod from the lowest position to the highest one. To reduce the unevenness of the load on the electric motor of the pumping unit, as well as the cost of electricity, an additional wellhead equilibration system is proposed, which allows the wellhead rod to be loaded with a vertical force constantly pointing upwards. During the operation of the pumping unit, there is a loss of energy while transferring it from the engine to the conversion mechanism, caused by the slippage of the belts due to the loosening of their tension. To prevent the belts from loosening, a mechanism in which the axial distance between the motor pulleys and the pumping unit gearbox is adjusted by changing the angle of the motor platform is proposed.

A Study on the CO2-Enhanced Water Recovery Efficiency and Reservoir Pressure Control Strategies

CO2 geological storage (CGS) proved to be an effective way to mitigate greenhouse gas emissions, and CO2-enhanced water recovery (CO2-EWR) technology may improve the efficiency of CO2 injection and saline water production with potential economic value as a means of storing CO2 and supplying cooling water to power plants. Moreover, the continuous injection of CO2 may cause a sharp increase for pressure in the reservoir system, so it is important to determine reasonable reservoir pressure control strategies to ensure the safety of the CGS project. Based upon the typical formation parameters of the China Geological Survey CO2-EWR test site in the eastern Junggar Basin, a series of three-dimensional (3D) injection-extraction models with fully coupled wellbores and reservoirs were established to evaluate the effect of the number of production wells and the well spacing on the enhanced efficiency of CO2 storage and saline production. The optimal key parameters that control reservoir pressure evolution over time are determined. The numerical results show that a smaller spacing between injection and production wells and a larger number of production wells can enhance not only the CO2 injection capacity but also the saline water production capacity. The effect of the number of production wells on the injection capacity and production capacity is more significant than that of well spacing, and the simulation scenario with 2 production wells, one injection well, and a well spacing of 2 km is more reasonable in the demonstration project of Junggar Basin. CO2-EWR technology can effectively control the evolution of the reservoir pressure and offset the sharp increase in reservoir pressure caused by CO2 injection and the sharp decrease of reservoir pressure caused by saline production. The main controlling factors of pressure evolution at a certain spatial point in a reservoir change with time. The monitoring pressure drops at the beginning and is controlled by the extraction of water. Subsequently, the injection of CO2 plays a dominant role in the increase of reservoir pressure. Overall, the results of analysis provide a guide and reference for the CO2-EWR site selection, as well as the practical placement of wells.

Capacity Requirements Planning in Water Injection Plant (WIP) Facilities of the Exploration Wells at Oil Company

In production wells, in line with the production time there is a decrease in reservoir pressure and this condition causes a reduction in the economic value of the well. The problem of wells that have decreased production capability caused by a decrease in reservoir pressure can be overcome by means of artificial lift methods. Water injection is a method of injecting by re-injecting water that is carried along with oil during the petroleum production process using an injection pump. Based on this, capacity planning is needed in relation to the need for injection pump engines in the operating area so that the petroleum production process can run smoothly. The method used is to perform formation water forecasting needed in each exploration wells based on historical data injection water formation to obtain a plan regarding the capacity of the pump engine to be used in the coming period. Based on the results of forecasting, it is known that 32 periods have the possibility to exceed WIP capacity by 2000 bwpd. From the observations, an additional 2000 bwpd is needed to increase WTP capacity to 4000 bwpd with the proposed cost needed for the procurement of injection water per month is Rp. 22.083.333 compared to the previous required cost of Rp. 32.129.400,- per month.

Numerical simulation of multi-seam coalbed methane production using a gray lattice Boltzmann method

Multi-zone or multi-seam commingled production in CBM reservoir is an attractive option for extending and/or increasing existing gas production. To solve the problem of interlayer interference during commingled production, with varying permeability and pressure difference between coal seams, numerical simulations are carried out using a gray lattice Boltzmann method. Under different conditions of multi-seam commingled production, the pressure and velocity distributions are obtained. Then, the effects of permeability and pressure contrast on multi-seam commingled production are investigated. The results show that under the condition of commingled production with different permeability contrast, a greater permeability contrast will lead to a greater difference in gas production of each seam. And the smaller the reservoir permeability is, the faster the decrease of reservoir pressure near the wellbore is. For commingled production with different pressure contrast, the interlayer interference coefficient increases linearly with the increase of the pressure contrast. The interference degree of low pressure seam is far greater than that of high pressure seam. A lower reservoir permeability will lead to a greater interference coefficient. The research results provide a basis for revealing the interlayer interference mechanism, production dynamic analysis and production system optimization in multi-seam commingled production.

Optimal injection rate of water in the Guide Basin hot dry rock mining project

The energy reserves of hot dry rock resources are huge, thus a model to predict engineering production for efficient and stable development and utilization is sought. Based on the geological characteristics of dry rock resources in Guide Basin, Qinghai Province, China, the fully coupled wellbore–reservoir simulator—T2Well—is used to model a production system using water as a heat transfer medium and simulate the system’s operation to analyze the influence of different injection rates on heat extraction. In later production stages, output temperature and reservoir pressure decrease by 10–30°C and 0.5–30 MPa, depending on injection rate; this occurs earlier and to a greater extent at higher injection rates; thermal breakthrough also occurs earlier (7–10 years). The heat extraction rate is 1–20 MW and the cumulative heat extracted is 2.1–24.2 × 105 J. Lower injection rates result in relatively low heat extraction rates. For maximum economic benefit, an injection rate of 50–75 kg/s is ideal.

Gas production technologies on gas fields at final stage of development

About 80% of produced natural gas in Russia is taken from Cenomanian gas deposits of Western Siberia. For a long time, the main volume of gas production was selected on the largest unique deposits in the region - Medvezhye, Urengoyskoye, Yamburgskoye. Currently, the development of Cenomanian deposits of these fields has approached the final stage, and the production of initial balance reserves has exceeded 80 percent threshold. It is known that during gas sampling of more than 80-85%, there is a significant decrease in reservoir pressure, and further extraction of the remaining reserves on condition of their main transportation becomes economically inefficient due to the sharply increasing cost of the extracted products. Residual gas reserves of such deposits are not profitable for production, but with deep compression some of them can be extracted. This part is called “low-pressure gas” in Russian terminology. The assessment has shown that reaching an 85 percent production threshold of balance reserves of Cenomanian deposits, only on Medvezhye, Urengoy and Yamburg fields, there will be at least 1 trillion 700 billion cubic meters of gas, of which more than 600 billion cubic meters is “low-pressure gas”. The experience of cost-effective extraction of such reserves is currently lacking. The high degree of infrastructure development and the importance of socio-economic factors require the introduction of new technical solutions to extend the development and increase the final gas recovery of these fields. Today, within the walls of research and design institutes dealing with the problems of developing Cenomanian gas deposits, the tasks are solved to create new and improve already approved technological approaches for the development of “low-pressure gas” deposits. In this article, an attempt is made to define “low-pressure gas”, to estimate its volumes for currently developed Cenomanian gas deposits of Yamal-Nenets Autonomous District and to give a brief description of proven and promising technical solutions for the well operation at the final stage of development.

An improved productivity model in coal reservoir and its application during coalbed methane production

Permeability of coal reservoir is a key parameter affecting coalbed methane (CBM) productivity. The dynamic variation of permeability depends on the effect of effective stress, coal matrix shrinkage and gas slippage during CBM well drainage. On the basis of S-D stress-permeability model, a dynamic prediction model of coal reservoir permeability considering effective stress, coal matrix shrinkage and gas slippage effect (is called “three effects”) is established. The dynamic change of permeability in CBM development is revealed. It shows that permeability initially drops and then rises. An improved CBM productivity model considering “three effects” is derived, and the influence law of “three effects” on CBM production during CBM well drainage is revealed. The results of the theoretical model are compared with the field data, and the reliability of the theoretical model is further verified. During CBM production, with the decrease of reservoir pressure, the effective stress increases. Before reservoir pressure reaches the critical desorption pressure, the effective stress effect is dominant and the permeability of coal reservoir declines; after the reservoir pressure declines to below the critical desorption pressure, the coal matrix shrinkage effect will play a dominant role in the permeability variation, and the permeability will start to increase at lower pressure. It is critical not only to avoid too much initial pressure drawdown, which decreases well productivity; but also to ensure matrix shrinkage effect improve the permeability and productivity of coal reservoirs in longer term.

IMPROVEMENT OF HYDROCHLORIC ACID FORMATION TREATMENT FOR VOLGO-URALS CARBONATES

Background. At the present stage of development of the oil and gas industry, the structure of oil reserves in the Republic of Bashkortostan is deteriorating. The share of hard-to-recover oil reserves, including those associated with carbonate reservoirs, is increasing. More than 2 0 % of residual and hard-to-recover oil reserves of Bashkortostan are found in carbonate reservoirs. Productive deposits containing oil deposits have a complex geological structure. The development of these reserves will allow maintaining the current level of hydrocarbon production for a long time. The use of hydrochloric acid carbonate reservoirs treatment allows to increase the efficiency of exploitation of these deposits. However, oil deposits in carbonate reservoirs are often operated with an ineffective water flooding system or on a natural regime, which leads to a decrease in reservoir pressure in the bottomhole zone of producing wells. The use of standard hydrochloric acid treatment of production wells under these conditions proves ineffective. In this regard, studies have been conducted aimed at increasing the effectiveness of measures to intensify oil production, which, of course, is an urgent task. Aims and Objectives. Improvement of the hydrochloric acid treatment for Volga-Ural carbonate reservoirs in conditions of low reservoir pressure to increase the efficiency of the method of stimulation of the inflow to the wells. Metods. The mechanism of action of the acid solution on the productive reservoir is based on analytical methods of research. Determination of the rate of reaction of acid solutions with carbonate rock using reaction moderators and reagents is based on a generalization of the results of laboratory studies. Commercial types of research were used in experimental-industrial tests of the proposed method of hydrochloric acid exposure. The results of field work on the intensification of the inflow to production wells were processed using analytical and mathematical methods. Rezults. Based on the concept of the mechanism of the process of oil displacement from weakly permeable carbonate reservoirs, methods for treating the bottomhole zone of producing wells, including those for low reservoir pressure, are proposed. The results of the implementation of the proposed method made it possible to increase the production rate by more than 2 times in comparison with the treatment performed by traditional technology, and the duration of the effect from treatment was much larger. Conclusion. The application of the proposed methods of hydrochloric acid treatment during the intensification of the influx from the carbonate layers of the Bashkir and Vereiskian, Tournaisian stages, including for the conditions of low reservoir pressure in the Republic of Bashkortostan oil fields, will significantly improve the efficiency of the work.

MODERN APPROACH TO THE CHOICE OF COMPOSITIONS FOR TEMPORARILY BLOCK THE PRODUCTIVE RESERVOIR WELLS IN THE FIELDSWITH COMPLICATED MINING AND GEOLOGICAL CONDITIONS

In modern conditions the complexity of conducting the repair work of wells has been steadily increasing. This is due to a significant deterioration of mining and geological conditions of oilfields - decrease of reservoir pressure, deterioration of reservoir properties of productive formations, the infiltration of the formation water, and others. Also, there are still relevant problems associated with conducting the works on wells in terrigenous reservoirs with heterogonous permeability containing clay minerals. In such conditions on the first place arises the question of preservation of reservoir properties of formations during the repair works. This problem can be solved with the use of modern highly effective blocking compositions with condensable solid phase.

The impacts of microcosmic flow in nanoscale shale matrix pores on the gas production of a hydraulically fractured shale-gas well

Special nanoscale storage mechanisms and pore radii create complex shale gas transport mechanisms. Shale gas reservoir production performance evaluations are challenging due to difficulties associated with microcosmic flow mechanisms, such as Knudsen diffusion, surface diffusion, adsorption and desorption. A thorough understanding of the effects of these transport mechanisms on shale gas production can help to develop new and improved shale gas production prediction models. This paper derives a unified apparent permeability equation based on the Knudsen number and four flow regimes, incorporating viscous, slip, transition and free molecule flows. The new apparent-permeability model also considers the surface diffusion, adsorption layer and tortuous diffusion path. Fully coupled differential equations were developed for a hydraulic fracture and matrix system based on these microcosmic transport mechanisms and using the finite difference method. A sensitivity analysis was performed to investigate the impacts of several parameters on production, including the nanopore radii, Langmuir parameters and bottom-hole flow pressure. The simulation results demonstrate that the microcosmic flow mechanisms significantly impact shale gas production. Gas production increases as the Langmuir parameters increase, but the rate of the increase decreases over time. Knudsen diffusion and surface diffusion become more prominent as the pore radius and reservoir pressure decrease. The adsorption layer cannot be ignored at sufficiently small pore radii.

Micro/Nano-pore Network Analysis of Gas Flow in Shale Matrix.

The gas flow in shale matrix is of great research interests for optimized shale gas extraction. The gas flow in the nano-scale pore may fall in flow regimes such as viscous flow, slip flow and Knudsen diffusion. A 3-dimensional nano-scale pore network model was developed to simulate dynamic gas flow, and to describe the transient properties of flow regimes. The proposed pore network model accounts for the various size distributions and low connectivity of shale pores. The pore size, pore throat size and coordination number obey normal distribution, and the average values can be obtained from shale reservoir data. The gas flow regimes were simulated using an extracted pore network backbone. The numerical results show that apparent permeability is strongly dependent on pore pressure in the reservoir and pore throat size, which is overestimated by low-pressure laboratory tests. With the decrease of reservoir pressure, viscous flow is weakening, then slip flow and Knudsen diffusion are gradually becoming dominant flow regimes. The fingering phenomenon can be predicted by micro/nano-pore network for gas flow, which provides an effective way to capture heterogeneity of shale gas reservoir.

A half century of reservoir property changes in the Szentes geothermal field, Hungary

The general characterization of the Hungarian Szentes geothermal field is presented based on the review of previous research and is supplemented with the analysis of well hydraulic tests. Forty thermal wells were included in the study area, producing mainly from Upper Pannonian sandstone reservoirs. The intensive and long-term production of thermal water reservoirs without reinjection resulted in significant reservoir pressure decrease from natural conditions. By means of deep-well pressure build-up curves, deep-well capacity curves and surface pressure curves the reservoir condition changes were described in the last half century.

A damage model for volcanic edifices: Implications for edifice strength, magma pressure, and eruptive processes

AbstractMonitoring of large basaltic volcanoes, such as Piton de la Fournaise (La Réunion Island, France), has revealed preeruptive accelerations in surface displacements and seismicity rate over a period of between 1 h and several weeks before magma reaches the surface. Such eruptions are attributed to ruptures of pressurized magma reservoirs. Elastic models used to describe surface deformation would assume that accelerations in surface deformation are due to increases in reservoir pressure. This assumption requires changes in magma or pressure conditions at the base of the magma feeding system that are unrealistic over the observed timescale. Another possible cause for these accelerations is magma pressure in the reservoir weakening the volcanic edifice. In the present study, we modeled such weakening by progressive damage to an initially elastic edifice. We used an incremental damage model, with seismicity as a damage variable with daily increments. Elastic moduli decrease linearly with each damage increment. Applied to an initially elastic edifice with constant pressure at the base of the system, this damage model reproduces surface displacement accelerations quite well when damage is sufficient. Process dynamics is controlled by the damage parameter, taken as the ratio between the incremental rupture surface and the surface to be ruptured. In this case, edifice strength and magma reservoir pressure decrease with decreasing elastic moduli, whereas surface displacement accelerates. We discuss the consequences of pressure decreases in magma reservoirs.

Dynamic threshold pressure gradient in tight gas reservoir

Experimental approach was performed in this paper to study the threshold pressure gradient (TPG) in tight gas reservoir. The nonlinear flow behavior of tight gas reservoir was investigated at first, three zones of flow curve are divided to describe the nonlinear behavior of gas flow in tight formation: solid–gas viscous force zone, slippage zone and low-speed turbulent zone. On this basis, experiments using modified procedure were made in order to clarify the influence of pore pressure on TPG, results show that TPG of tight gas reservoir is highly effected by pore pressure and conventional experimental methods will lead to a significant error. And then, TPG during the development of tight gas reservoir was tested. The results we obtained demonstrated that there exists ‘Dynamic TPG Effect’ during the development process of tight gas reservoir: TPG is increasing along with the decrease of reservoir pressure (pore pressure). New concepts of ‘TPG Rising Cone’ and ‘TPG Sensitivity Coefficient’ are defined to characterize the dynamic TPG of tight gas reservoir. Finally, experiments were carried out to investigate the influence of permeability and water saturation on dynamic TPG. Results indicate that ‘TPG Rising Cone’ is more significant in reservoir with low-permeability or high water saturation.

CFD flow analysis in the centrifugal vortex pump

Purpose – Aging of the oil wells leads to a decrease in reservoir pressure and also to an increase in the water, gas and abrasive particles content. Therefore, there is a need for the oil pumps exploitation characteristics improvements. This paper aims to generate a valuable numerical model which will provide a useful tool to study various cases. Design/methodology/approach – Computational fluid dynamics (CFD) analysis of the generation of so-called coherent structures of eddies and turbulence in the peripheral area of the vortex rotor mounted at the back side of centrifugal rotor was undertaken. After detailed analysis of the influence of the used turbulence models on the results, a hybrid turbulent model Detached Eddies Simulation (DES) was chosen as the most suitable. Findings – Numerical control volume method with unsteady solver and DES turbulence model was proven to be valuable tool for flow analysis in the centrifugal pumps. Having in mind that DES turbulence model consumes much less computational time than large eddies turbulence model, this is a very useful fact that resulted from this research. Practical implications – The proven numerical model is robust and reliable enough to become a standard method in simulating flow and other physical phenomena occurring in centrifugal pumps and similar turbo machines. This makes it possible to easily research different factors that influence their performances. Originality/value – Comprehensive experimental and CFD study was performed which made it possible to conduct detailed validation and verification of described CFD model.

Foam-EOR Pilot: Mature Volatile-Oil Reservoir Under Miscible-Gas Injection

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 16984, ’Successful Foam-EOR Pilot in a Mature Volatile-Oil Reservoir Under Miscible-Gas Injection,’ by A. Ocampo, A. Restrepo, SPE, H. Cifuentes, SPE, J. Hester, N. Orozco, C. Gil, and E. Castro, Equion Energia, and S. Lopera and C. Gonzalez, Universidad Nacional de Colombia, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. A successful field trial in which foam was used as a gas- injection conformance enhancer was implemented in the Cusiana field in Colombia. An extensive front-end loading (FEL), including chemical-product screening, studying foam stability at reservoir conditions, coreflood experiments, reservoir modeling, and careful selection of well candidates, was executed for this pilot. The treatment was performed in a gas-injection well in the northern part of the field that had already attained a high recovery factor (RF) with high levels of gas recycling. The operation was performed by use of a surfactant-alternating-gas (SAG) method. Introduction The Cusiana field is in the foothills of the Eastern Mountain chain in Colombia, and initial production was in 1994. The field comprises three stacked reservoirs (Mirador, Barco, and Guadalupe) and two fluid systems (both volatile oils) with a rich-gas cap at near-critical conditions (pressures and temperatures greater than 5,000 psia and 250°F, respectively). The initial in-place volumes were 1.5 billion STB of oil and more than 3 Tcf of gas, with the Mirador formation containing approximately 60% of the total fluid. Development strategies have included natural depletion, gas recycling, water injection, and gas-injection redistribution. Gas recycling and redistribution provided the best recoveries. The Mirador reservoir is a low- porosity quartzarenite with significant heterogeneities in permeability, both vertically and areally. The reservoir was developed with extensive gas reinjection, beginning in the early days of production with the gas-injection wells updip on the structure. This strategy proved beneficial from the very early stages of gas injection with regard to efficient first-contact miscibility and the favorable location of the injectors. The result has been RFs greater than 50% for most of the Mirador units. After approximately 10 years of gas reinjection, high levels of recycling were observed as a result of reservoir heterogeneities and a less-efficient gas-enrichment process because of the decrease in reservoir pressure below the minimum miscibility pressure. Those conditions led to unrecovered oil in areas that are difficult to access, such as the oil rim between the producers and the aquifer, poor-quality rock layers, and bypassed areas between the producers and injectors.

Dynamics of inelastic deformation of porous rocks and formation of localized compaction zones studied by numerical modeling

The paper presents a numerical analysis of the inelastic deformation process in porous rocks during different stages of its development and under non-equiaxial loading. Although numerous experimental studies have already investigated many aspects of plasticity in porous rocks, numerical modeling gives valuable insight into the dynamics of the process, since experimental methods cannot extract detailed information about the specimen structure during the test and have strong limitations on the number of tests. The numerical simulations have reproduced all different modes of deformation observed in experimental studies: dilatant and compactive shear, compaction without shear, uniform deformation, and deformation with localization. However, the main emphasis is on analysis of the compaction mode of plastic deformation and compaction localization, which is characteristic for many porous rocks and can be observed in other porous materials as well. The study is largely inspired by applications in petroleum industry, i.e. surface subsidence and reservoir compaction caused by extraction of hydrocarbons and decrease of reservoir pressure. Special attention is given to the conditions, evolution, and characteristic patterns of compaction localization, which is often manifested in the form of compaction bands. Results of the study include stress–strain curves, spatial configurations and characteristics of localized zones, analysis of bifurcation of stress paths inside and outside localized zones and analysis of the influence of porous rocks properties on compaction behavior. Among other results are examples of the interplay between compaction and shear modes of deformation. To model the evolution of plastic deformation in porous rocks, a new constitutive model is formulated and implemented, with the emphasis on selection of adequate functions defining evolution of yield surface with deformation. The set of control parameters of the model is kept as short as possible; the parameters are carefully selected to have simple and intuitive physical interpretation whenever possible. Results demonstrate that evolution of the yield surface with deformation has major influence on the resulting characteristics of deformation patterns, which is not sufficiently acknowledged in the literature.

Laboratory Investigation of Effective Stresses' Influence on Petrophysical Properties of Sandstone Reservoirs During Depletion

Abstract An increase in effective stresses takes place in reservoirs as a consequence of fluid production, a well-known phenomenon in both shallow and deep reservoirs. It may seem reasonable to assume that permeability and porosity decrease as pore pressure declines, since both effective radial and axial stresses become intensified during reservoir depletion. However, laboratory results show that this is not always the case. Porosity certainly decreases as a result of the compaction process, which allows the breakage of grain-to-grain cement bonds. Grain particles will become more compacted as both lateral and axial effective stresses increase. On the other hand, permeability shows no definite trend. In this paper, a series of delicate experimental procedures were conducted to reveal some of the most intriguing phenomena in pore collapse and their impact on permeability. Sandstone samples were tested using a triaxial set-up. Based on the experimental results of this study, in weak reservoir formations, pore collapse does not occur suddenly. Rather, rocks gradually compact as grain-to-grain cement bonds break down. It was found that permeability indeed changes as effective stresses increase. However, the pathway to permeability was found to be much more complex than previously stipulated. It was discovered that enhancement or damage to permeability is not a function of pore collapse alone. Other factors, such as stress path, initial porosity, particle size, particle shape and particle distribution play a major role in determining what type of alteration in permeability occurs and to what magnitude that alteration would be. Introduction Traditionally, petrophysical properties data are very crucial for reserves assessment and fluid flow characterization of petroleum reservoirs. A great deal of money and effort are usually allocated in order to accurately estimate these properties. Permeability and porosity are among those properties and are by far the most important. Porosity is the key for reserves estimates while permeability is the main parameter to predict flow rates, design drawdown and, therefore, wellbore completion. Until recently, the common belief was that, once determined, these properties remain constant throughout the production life of the reservoir. Studies(1–3), including this paper, showed that this is not a realistic assumption. During the pressure depletion process, as production from the reservoir continues, effective stresses within the reservoir increase. It is understood that the effect of reservoir stresses on porosity and permeability of the reservoir is more severe when porosity and permeability are high, although some experimental studies like Hubbert and Willis(4), Voight and St. Pierre(5) and Rosepiler(6) showed this effect is still significant, even at low porosity and permeability. It is also understood that stress paths have a large influence on horizontal and vertical permeability, and also on porosity. The elastic uniaxial strain model is mostly used in reservoir engineering to describe production-induced changes in horizontal stress due to pore pressure decline (pressure depletion). It predicts the total horizontal stress by using overburden stress, reservoir pressure decrease and material mechanical parameters. The principal assumption in this model is that there is no lateral deformation (zero horizontal strain condition) during the depletion process.