Reduction In Reservoir Pressure Research Articles

Influence of gravity on methane hydrate dissociation characteristics by depressurization in marine hydrate reservoirs

Since the thickness of hydrate-bearing sediments is usually tens to hundreds of meters, the influence of gravity on hydrate dissociation characteristics can no longer be ignored. In this study, experimental simulations were designed to investigate the influences of gravity on hydrate dissociation characteristics by depressurization. The experimental results showed that for sealed water-rich marine hydrate reservoir, gravity could cause more water to migrate downward. The free pore space in sediments was thus rapidly vacated, resulting in faster hydrate dissociation and gas production. The average gas production rate increased from 0.018 mol/min to 0.038 mol/min. In addition, the free pore space at the top of the sediments was vacated first. Hydrate dissociation there was thus faster. For unsealed water-rich marine hydrate reservoir, gravity could not only cause more and faster migration of water, but also more easily cause the formation of dominant channels for water migration, leading to an effective reduction in reservoir pressure. The cumulative water yield increased from 1380g to 8950g. Hydrate thus dissociated. Hydrate dissociated faster at positions close to the mining well where the pressure was lower. These findings can provide deep insights into the spatial evolution of multiphase flows during the exploitation of natural gas hydrates.

Nodal Analysis of Naturally Flowing Wells in Faihaa Oil Field, Yamama Formation

This study focuses on the Yamama Formation, a significant carbonate reservoir in southern Iraq that is one of the most important productive reservoirs in the region. The Formation is characterized by porous limestone interspersed with thin layers of argillaceous and tight limestone. The Yamama reservoir in the Faihaa oil field is divided mainly into four units; YA, YB, YC, and YD. YA and YB units are considered to be the most important oil-bearing subunits due to their good petrophysical properties. The main objective of the study is to determine the optimum production rates of four naturally flowing wells in the Faihaa oil field using the Inflow Performance Relationship and Vertical Lifting Performance curves. The study investigates four critical parameters; tubing size, water cut, reservoir pressure, and wellhead pressure, and their impact on well performance. The study finds that wellhead pressure is the primary determinant of well performance, and deviations from the original tubing size have adverse effects on well performance. An increase in water cut beyond the recommended threshold, coupled with a reduction in reservoir pressure, results in decreasing well performance. The study underscores the importance of careful monitoring and analysis of these parameters to sustain and enhance well performance in the Faihaa oil field, providing valuable insights for well operators and petroleum engineers. The study's findings can be used to optimize well performance and increase oil production rates, with significant implications for the petroleum industry.

ASSESSMENT OF THE INFLUENCE OF CONTAMINATION OF THE BOTTOMHOLE ZONE OF THE FORMATION ON THE PERFORMANCE CHARACTERISTICS OF PRODUCTION WELLS

The reasons for the decrease in productivity of gas wells are characterized. The structure of the formation colmatation parameter is revealed. For the conditions of a model well, using mathematical dependencies, the influence of different values of the radii of the contaminated zone at the bottomhole formation zone, the multiplicity of the permeability coefficient of the contaminated formation zone and different degrees of reduction in reservoir pressure from the initial value on the productivity of gas wells was studied. The research results are presented in the form of graphical dependences of gas flow rate for the initial value of reservoir pressure on the permeability coefficient of the contaminated zone for different radii of the contaminated zone, on the radius of the contaminated zone for different values of the permeability coefficient of the contaminated zone, pressure along the radius of the contaminated zone 0.25, on the radius of the zone pollution of varying degrees of reduction in reservoir pressure according to the multiplicity of the permeability coefficient of the contaminated zone 2. According to the results of studies, with an increase in the multiplicity of the permeability coefficient of the contaminated zone, we will obtain a significant decrease in the gas flow rate, and the gas flow rate, the greater the value of the reservoir pressure. Zone contamination at high values of reservoir pressure has a significant impact on the reduction in gas production. Using the method of statistical processing of calculated data, the average optimal value of the contaminated zone radius was established to be equal to 0.25 for all values of the permeability coefficient of the contaminated zone and the average optimal value of the permeability coefficient of the contaminated zone to be 1.97.

Research on Transformation of Connate Water to Movable Water in Water-Bearing Tight Gas Reservoirs

The Dongsheng gas field is a water-bearing tight gas reservoir characterized by high connate water saturation. During gas production, the transformation of connate water into movable water introduces a unique water production mode, significantly impacting gas reservoir recovery. Current experimental and theoretical methods for assessing formation water mobility are static and do not address the transformation mechanism from connate into movable water. In this study, we considered dynamic changes in formation stress and proposed the mechanism for the transformation of connate water into movable water during depressurization, involving the expansion of connate water films and the reduction of pore volume. We developed a novel methodology to calculate the dynamic changes in movable and connate water saturation in tight reservoirs due to reservoir pressure reduction. Furthermore, we quantitatively evaluated the transformation of connate water into movable water in the Dongsheng gas field through laboratory experiments (including formation water expansion tests, connate water tests, and porosity stress sensitivity tests) and theoretical calculations. Results show that under original stress, the initial connate water saturation in the Dongsheng gas field ranges from 50.09% to 58.5%. As reservoir pressure decreases, the maximum increase in movable water saturation ranges from 6.1% to 8.4% due to the transformation of connate water into movable water. This explains why formation water is produced in large quantities during gas production. Therefore, considering the transition of connate water to movable water is crucial when evaluating water production risk. These findings offer valuable guidance for selecting optimal well locations and development layers to reduce reservoir water production risks.

Experimental Study on the Influence of Effective Stress on the Adsorption–Desorption Behavior of Tectonically Deformed Coal Compared with Primary Undeformed Coal in Huainan Coalfield, China

In order to explore the influences of effective stress change on gas adsorption–desorption behaviors, primary undeformed coal (PUC) and tectonically deformed coal (TDC) from the same coal seam were used for adsorption–desorption experiments under different effective stress conditions. Experimental results showed that gas adsorption and desorption behaviors were controlled by the coal core structure and the pore-fissure connectivity under effective stress. The coal matrixes and fissures were compressed together under effective stress to reduce connectivity, and it was difficult for gas to absorb and desorb as the stress increased in primary undeformed coal. The loose structure of tectonically deformed coal cores can help gas to fully contact with the coal matrix, resulting in higher adsorption gas volumes. The support of coal particles in tectonically deformed coal cores weakens the compression of intergranular pores when effective stress increases, which in this study manifested in the fact that while the volumetric strain of the coal matrix change rapidly under low effective stress, but the adsorbed gas volume did not decrease significantly. The reduction in effective stress induced the rapid elastic recovery of the coal matrix and the expansion of cracks, and increased desorption gas volumes. The stress reduction significantly increased the initial gas volume of the tectonically deformed coal, while promoting slow and continuous gas desorption in primary undeformed coal. Therefore, the promotion effect of the reservoir pressure reduction on gas desorption and coal connectivity enhancement can help to improve coalbed methane recovery in primary undeformed coal and tectonically deformed coal reservoirs.

Mechanism of the Enrichment and Loss Progress of Deep Shale Gas: Evidence from Fracture Veins of the Wufeng–Longmaxi Formations in the Southern Sichuan Basin

Natural fractures caused by tectonic stress in shale can not only improve the seepage capacity of shale, but also become the migration and loss channel of free gas. Calcite, quartz and other minerals in shale fracture veins record the fluid evolution information of the shale. Through the analysis of different types of fracture cements in the shale of the Silurian–Ordovician Wufeng–Longmaxi Formations in the southern Sichuan Basin, the effect of different fractures on shale gas construction or destruction was clarified. Geochemical investigations included the diagenetic mineral sequences in the hole–cavity veins, paleo-pressure recovery by Raman quantitative analysis, and the environments of diagenetic fluids traced by rare earth elements (REE) signatures. The density, composition, pressure, and temperature properties of CH4-bearing fluid inclusions were determined by Raman quantitative measurement and thermodynamic simulations to establish the trapping condition of the geo-fluids, and so constrain the periods of gas accumulation. The diagenetic sequences in the fracture veins can be summarized as follows: Cal-I→Qz-II→Cal-III. The Cal-I in the bedding fracture veins crystallized in the late Jurassic (~180 Ma), and originated from hydrothermal origin and diagenetic fluid; the Qz-II veins crystallized in the middle Jurassic (~190 Ma); the Cal-III veins in the high-angle fractures precipitated during the early Eocene (~12 Ma), and derived from atmospheric freshwater leaching. Pore fluid pressure gradually increased. The pressure coefficient of the shale gas reservoir gradually increased to strong overpressure from 160 Ma to 86 Ma. Between 75 Ma and the present day, the pore fluid pressure and the pressure coefficient in the shale reservoirs, having been affected by tectonic activities and strata uplift-erosion, have significantly reduced. Bedding slippage fractures play a constructive role in the enrichment of shale gas, and fracture slip can significantly improve fracture permeability. High-angle shear fractures usually cut through different strata in areas with strong tectonic activity, and destroy the sealing of the shale. The entrapment of primary methane gas inclusions recorded the process of excess reservoir pressure reduction, and indicated the partial loss of shale free gas.

Investigation of gas solubility and its effects on natural gas reserve and production in tight formations

In this study, the natural gas solubility in brine and its influence on natural gas reserve and production in a tight gas reservoir have been investigated by the integration of laboratory experiments, phase equilibrium calculations, and numerical evaluation. Experimentally, a visualized PVT cell has been used to measure natural gas solubility at various pressures, temperatures, and salinity. Theoretically, the solubilities of natural gas and natural gas components are calculated using the phase equilibrium theory and equation of state (EOS), which are calibrated by the experimental data first. A sensitivity analysis is implemented to investigate the effects of pressure, temperature, and salinity on natural gas solubility. Subsequently, with the assistance of numerical simulation, the influence of the dynamic gas solubility on the natural gas reserve and production is examined in a tight gas reservoir in Middle Permian Shihezi Formation, Ordos Basin, China. The natural gas solubility is found to be 2.91 m3/m3 at initial reservoir conditions, which contributes to an increase of 1.33% in natural gas reserve. For natural gas and formation brine with specific composition, the gas solubility decreases gradually with the reservoir pressure reduction in the production process. The production prediction indicates that the cumulative gas production from tight formation requires calibration if the dynamic gas solubility is considered. In the field-scale simulation, the cumulative gas production after 10 years is 0.52% higher than the case not considering the dynamic natural gas solubility.

Sand production onset using 3D Hoek–Brown criterion and petro-physical logs: a case study

ABSTRACT Sand production is a serious problem while oil and gas producing from unconsolidated formation. The reasons for such damage are the loss of the balance of the rock’s stress in a drilling situation, create a momentum in the grain by fluid movement, reduction in reservoir pressure, and fatigue formation in the rock. Therefore, it is significant to forecast and evaluate the sanding onset of the wells with the intention of drilling and production condition optimisation. In this study, first, a geo-mechanical model based on the reservoir and petro-physical properties was established. Then, a new analytical shear failure sanding onset prediction model was derived on the basis of the three-dimensional Hoek–Brown failure criterion. Furthermore, the developed model was applied to the prediction of the critical drawdown pressure causing sand production in one of the wells drilled in one of the fields located in southwest Iran. Finally, the sensitivity of the relevant parameters with respect to the sanding onset in this well was evaluated. The results showed that the three-dimensional Hook–Brown model was a good fit with well number 19 of the Asmari field. Therefore, this criterion was recommended for the sand production analysis in this oil field.

Capillary trapping induced slow evaporation in nanochannels

Unconventional reservoirs are massive and providing an increasing share of global energy with a broad group of stakeholders in academia, industry and government. The size of pores in unconventional reservoirs can be down to nanometers, necessitating a deeper fundamental understanding of fluid phase properties at nanoscale. In this paper, we investigate capillary trapping induced slow evaporation of n-pentane in nanochannel arrays through isothermal pressure drawdown to mimic the hydrocarbon release in nanopores of low-permeability reservoirs. Importantly, the capillary trapping forms during a slow reservoir pressure reduction process and significantly impedes liquid evaporation. Compared to the evaporation case without any capillary trapping, the global evaporation rate is ~16 times lower, which unfavorably affects gas recovery. In addition, we observe liquid corner flow in assisting evaporation in nanochannel, providing important experimental evidence towards previous theoretical study. In brief, our work reveals a type of anomalous evaporation at nanoscale that is fundamentally relevant to shale gas recovery. The experimental and modeling finding indicates that regulating pressure drawdown at an appropriate rate plays a key role in efficiently extracting shale gas.

A novel technique combining the cyclic steam stimulation and top gas injection for increasing heat efficiency

In the first production period of cyclic steam stimulation (CSS), the oil production rate becomes high due to reducing oil viscosity and increasing reservoir. Even though the remaining heat is still available in the surroundings of the well, the production rate declines too sharply resulting from the reservoir pressure reduction. This paper aims to maintain the oil production rate, which utilizes the remaining heat in the reservoir with a gas top injection. After the oil production rate declines, the gas is injected into the top side of the formation which pushes crude oil to the lower part of the reservoir. Finally, the crude oil moves to the production perforation. The result indicates that the optimum volume gas injection is 6500 MMSCF. In such method, increasing reservoir thickness will be more favorable because the gas spreads more laterally and dissolves to the oil phase. In the case of extended cycle production time, the steam effectiveness will increase. To get the most favorable operation condition, the reservoir thickness must be more than 20 ft. In the optimum case, the cumulative oil production increases 3.5 times and the cumulative steam oil ratio decreases 60% compared to CSS-conventional.

Heterogeneities and Intra Sand-Body Compartmentalization in Late Oligocene Delta-Front Deposit, Niger Delta, Nigeria

This paper presents the study of the heterogeneity in lithofacies, porosity, permeability, mineral grain density, pore-throats sizes and hydraulic rock types and the intra sand-body compartmentalization in cored delta-front deposit of Greater Ughelli depobelt of Niger Delta. Sedimentological study of core samples results in the identification of nine lithofacies and the interpretation of environments of deposition as mainly proximal and distal delta-front mouth bar. The sand unit indicates moderate to excellent reservoir quality with core porosity between 16.2 and 29.5% and permeability between 16.8 and 7,560 md. Dykstra-Parsons core permeability distribution coefficient of 0.97 indicates that the studied reservoir sand-body is vertically highly heterogeneous, with high potential for vertical intra sand-body compartmentalization. Graphical cluster analysis of Flow Zone Indicators (FZI) led to the identification of nine Hydraulic Flow Units (HFU) with distribution controlled by depositional facies. The prediction of permeability, porethroats (r35) and flow zone indicator values of the reservoir in an uncored-well using predictive mathematical models developed with multiple regression analysis enabled the inter-well correlation of hydraulic flow units and indicates lateral continuity of reservoir compartments. An intra sand-body compartmentalization evaluated with core permeability values, Winland r35 coefficients and flow zone indicators was corroborated with formation pressure data analysis. Results show that the studied delta front-mouth bar reservoir is vertically compartmentalized by intercalated shales. Fractures in over-pressured zones were found to reduce vertical reservoir fluid compartmentalization by intercalated shales. However, reduction in reservoir pressure due to hydrocarbon production can result in dynamic compartmentalization and consequently, reduction in hydrocarbon recovery.

Effect of Elemental-Sulfur Deposition on the Rock Petrophysical Properties in Sour-Gas Reservoirs

Summary The deposition of elemental sulfur as a solid phase results in plugging the pore space available for gas flow and reduces the reservoir productivity. Elemental sulfur also can be deposited as a liquid phase if the reservoir temperature is greater than 115°C. The liquid sulfur restricts the inflow of gas because of the big density difference between liquid sulfur and gas, which could be 20 times or more. For isothermal conditions in the reservoir, the reduction in reservoir pressure to lower than a critical value causes the elemental sulfur to deposit in the formation, and in turn the gas-well productivity is affected. Accurate prediction of sulfur deposition will help better manage sour-gas reservoirs with potential sulfur-deposition problems. In this paper, a new analytical model was developed to predict the effect of sulfur deposition on the damage of the near-wellbore region. The damage was quantified through the investigation of the effect of sulfur deposition on rock porosity, relative permeability of the gas phase, and the change in rock wettability. The main objective of this model is to investigate the effect of radial distance on formation damage. Different rock- and fluid-property correlations were used in the model. Previous studies did not consider the change in gas properties with pressure, and numerically modeled the sulfur deposition as a condensate in a gas/condensate reservoir. This paper will consider sulfur adsorption, and the actual physical properties of the sulfur will be used in the developed model. The optimum gas-flow velocity that will maximize the sulfur solubility in the gas will be determined. A coreflood experiment was performed to determine the effect of sulfur deposition on the carbonate-rock permeability, porosity, and wettability. The experiment was used to determine the effect of sulfur adsorption on the rock petrophysical properties. The contact angle was measured for a carbonate core saturated with sulfur by use of a pendant-drop tensiometer. Analytical and numerical solutions showed that the deposition of sulfur was affected by the radial distance from the wellbore and sulfur-solubility changes as a function of the pressure drop. Sulfur deposition was found to have a great effect on the rock wettability, and in turn the gas production will be affected. The model can be used to predict the critical flow velocity that the gas can flow without precipitating sulfur. The optimum gas-flow velocity was estimated to be a range that maximizes the sulfur solubility in the gas. It was confirmed experimentally that the sulfur deposition reduced the carbonate-core porosity and permeability, and changed the contact angle (rock wettability). The contact angle increased, which means sulfur adsorption on the rock surfaces changed the rock toward more-gas-wet rock.

Sensitivity of compaction-induced multicomponent seismic time shifts to variations in reservoir properties

Pore-pressure variations inside producing reservoirs result in excess stress and strain that influence the arrival times of reflected waves. Inversion of seismic data for pressure changes requires better understanding of the dependence of compaction-induced time shifts on reservoir pressure reduction. Using geomechanical and full-waveform seismic modeling, we investigate pressure-dependent behavior of P-, S-, and PS-wave time shifts from reflectors located above and below a rectangular reservoir embedded in a homogeneous half-space. Our geomechanical modeling algorithm generates the excess stress/strain field and the stress-induced stiffness tensor as linear functions of reservoir pressure. Analysis of time shifts obtained from full-waveform synthetic data shows that they vary almost linearly with pressure for reflectors above the reservoir, but become nonlinear for reflections from the reservoir or deeper interfaces. Time-shift misfit curves computed with respect to noise-contaminated data from a reference reservoir for a wide range of pressure reductions display well-defined global minima corresponding to the actual pressure. In addition, we evaluate the influence of the reservoir width on time shifts and the possibility of constraining the width using time-lapse data. We also discuss the impact of moderate perturbations in the strain-sensitivity coefficients (i.e., third-order stiffnesses) on time shifts and on the accuracy of pressure inversion. Our feasibility analysis indicates that the most stable pressure estimation from noisy data is provided by multicomponent time shifts from reflectors below the reservoir. For multicompartment reservoirs, time shifts can be accurately modeled by linear superposition of the excess stress/strains computed for the individual compartments.

Simulation of Khangiran gas treating units for various cooling scenarios

Khangiran refinery sour gas feed has been acquired from Mozdouran reservoir in the past twenty eight years (1982–2010). In this period, the reservoir pressure has been dropped from 6600 psia to less than 5000 psia. It is anticipated that the pressure decrease will continue (even more rapidly due to higher production rates and sharper decrease in gas compressibility factor) in the near future. This considerable reduction in reservoir pressure has lead to appreciable increase in sour gas temperature entering the gas treating unit (GTU) due to Joule–Thompson effect. Such temperature increase had various adverse effects on the performance of the GTU process (e.g. higher contactors temperature peaks and larger antifoam consumptions). A variety of cooling scenarios have been considered in the present article. The required cooling facilities were designed for lowering the temperature of sour gas or lean solvent by air or water. The corresponding entire GTU processes were then simulated using both HYSYS and Aspen software’s. The simulation results indicate that the sour gas cooling scenario is not sufficiently effective because of the temperature peak encountered in the absorption towers. Furthermore, although the solvent cooling strategy was more effective from both economical point of view and its impact on the contactor temperature profile, however it may lead to some operational difficulties resulting from heavy hydrocarbons condensation. To avoid such predicaments, both sour gas and lean solvent streams should be cooled simultaneously via air coolers.

Mitigation planning for large-scale storage projects: multiple injection zones and reservoir pressure reduction engineering design

Abstract Effective mitigation plans are an absolutely critical component of mitigation plans for commercial-scale geologic carbon sequestration. One fundamental component of mitigation engineering design is immediate reduction of reservoir pressure. The Southwest Regional Partnership on Carbon Sequestration (SWP) is employing immediate reservoir pressure reduction as a primary mitigation tool in our geologic sequestration field projects. We are also employing multiple injection zones at the SWP deep saline injection site, both to maximize capacity and optimize mitigation plans. We developed models for each of our test sites to forecast optimum density and placement of injection and observation wells. Likewise, we designate certain observation wells as “observation-pressure- reduction,” or “OPR” wells. These are wells that serve as observation wells, but are engineered for quick conversion to production (pumping) wells to facilitate immediate pressure reduction, if needed. Results of our reservoir models suggest that immediate pressure reduction may stem geomechanical deformation, stem and/or close crack/fracture growths, shut down “piston-flow” displacement of brines into unintended reservoirs, slow leakage through wellbores, slow leakage of CO 2 through faults, and even induce closure of faults. Much like the injection wells, the distribution of such OPR wells is critical. For example, in ongoing Partnership field-testing, observation wells are being drilled that will serve as OPR wells, and we are using reservoir models to identify well locations that optimize both monitoring and mitigation potential. Reservoir model results also suggest that OPR wells can be converted to injection wells to maximize capacity and control reservoir pressure. For example, as one portion of the reservoir “fills” or if pressure control becomes problematic, the injection well can be converted to OPR mode, and the next well in the series (whether linear or in a grid design) can become an injection well. Simulation results suggest that if pressure reduction wells are used to “make space” for CO 2 by removing brine ahead of the CO 2 front, this pumping will also increase residual gas trapping by promoting horizontal migration. Additional results of our reservoir models suggest several caveats and potential problematic processes: (1) rapid reduction of reservoir pressure decreases CO 2 density, potentially leading to accelerated buoyancy effects, (2) premature CO 2 breakthrough may occur in pressure reduction wells, (3) pressure reduction decreases solubility of CO 2 in the formation water, potentially leading to exsolution and undesired phase changes, and (4) finally, a detailed cost- analysis must accompany such an engineering approach, because reservoir pressures directly affect compression injection costs, e.g., it is possible that pressure reduction wells may reduce or increase net costs of injection, depending on costs associated with water production and handling at the pressure reduction wells. We will show results of this sequestration field engineering approach for specific field tests, including ongoing geologic sequestration field-testing in several U.S. sites, including projects in Utah, New Mexico and Texas. The authors gratefully acknowledge the U.S. Department of Energy and NETL for sponsoring this Southwest Partnership project.

Adsorption‐induced coal swelling and stress: Implications for methane production and acid gas sequestration into coal seams

Sequestration of CO2 and H2S into deep unminable coal seams is an attractive option to reduce their emission into atmosphere and at the same time displace preadsorbed CH4 which is a clean energy resource. High coal seam permeability is required for efficient and practical sequestration of CO2 and H2S and recovery of CH4. However, adsorption of CO2 and H2S into coals induces strong swelling of the coal matrix (volumetric strain) and thus reduces significantly coal permeability by narrowing and even closing fracture apertures. Our experimental data on three western Canadian coals show that the adsorption‐induced volumetric strain is approximately linearly proportional to the volume of adsorbed gas, and for the same gas, different coals have very similar volumetric strain coefficient. Impacts of adsorption‐induced swelling on stress and permeability around wellbores were analytically investigated using our developed stress and permeability models. Our model results indicate that adsorption‐induced volumetric strain has significant controls on stress and permeability of producing and sequestrating coal seams and consequently the potential of acid gas sequestration. Coal seams may undergo >10 times enhancement of permeability around CH4‐producing wellbores due to a reduction in effective stress as a result of coal shrinking caused by methane desorption accompanying a reduction in reservoir pressure. Injection of H2S and CO2 on the other hand results in strong sorption‐induced swelling and a marked increase in effective stress which in turn leads to a reduction of coal seam permeability of up to several orders of magnitude. Injection of mixtures of N2 and CO2 such as found in flue gas results in weaker swelling, the amount of which varies with gas composition, and provides the greatest opportunity of sequestering CO2 and secondary recovery of CH4 for most coals. Because of the marked swelling of coal in the presence of H2S, even minor amounts of H2S result in a marked reduction in permeability, and hence sequestration of H2S in deep coals will be likely impractical. Furthermore, high stresses resulting from sorption of acid gases will potentially cause the coal to yield, fracture or slip, and produce fine particles, which further affect permeability and thus methane production and acid gas sequestration.

Influence of Effective Stress on the Acoustic Velocity and Log-Derived Porosity

Summary Experimental studies indicate that when effective stress increases, compressional wave velocity in porous rocks increases. Reservoir pressure reduction, resulting from hydrocarbon production, increases effective stress. For a rock with a given porosity the sonic log may show decreasing values as the pressure in the reservoir decreases. This in turn may lead to underestimation of the actual porosity of the reservoir rocks in low pressure reservoirs. The range of such underestimation for liquid saturated reservoirs may not be significant, but since the influence of effective stress on velocity increases as fluid saturation changes to gas, porosity underestimation by conventional velocity-porosity transforms for gas bearing rocks may increase. Examples are taken from partially depleted gas reservoirs in the Cooper basin, South Australia. The stress dependent nature of velocity requires that the in situ pressure condition should be considered when the sonic log is used to determine the porosity of gas producing reservoir rocks.

Orthotopic neo-bladder techniques

“Replacement” intestinal neo-bladders have been created or refined in many cases following cystectomy for various pathologies (iatrogenic, phlogistic, neurologic or neoplastic), in order to permit natural micturition and to keep the patient's body image intact. The requisites of the neo-reservoir are: adequate capacity, reduced internal pressure, an anti-reflux ureteral and continent urethral anastomosis. Based on the principles of hydraulic physics, literature considers that the double folding configuration (with front and sagittal folding guaranteeing the desynchronisation of peristalsis, maximum increase in capacity and reduction in reservoir pressure) is a confirmation of the excellency of the “spherical reconfiguration” of the detubularised segment. Thanks to the use of anti-reflux methods, the attention paid to the urethral anastomosis and the possibility in selected cases of nerve sparing surgery, today the orthotopic neo-bladder is the best and least costly diversion operation (no expendable materials used, reduced management time). The orthotopic diversion techniques most widely known and used in Italy are described. These involve the use of ileal, ileo-cecal, ceco-colic or sigmoid segments. Results are analysed from a clinical and urodynamic aspect. Points which are stili not clear concern the behaviour in time of the reservoir capacity, the repercussions on the upper urinary tracts and on the metabolism, as well as the long-term effects on the intestinal mucosa. Long follow-ups and comparative studies on homogeneous and numerically consistent case histories are therefore considered appropriate.

Economic Evaluation of Cycling Gas-Condensate Reservoirs With Nitrogen

Summary This work presents the results of an investigation of the economic feasibility of using cryogenically produced nitrogen as a substitute for natural gas to maintain reservoir pressure during cycling operations in gas-condensate reservoirs. Those economic factors unique to nitrogen cycling are discussed. It has been concluded that gas reservoirs with a condensate content in excess of 100 bbl/MMcf should be considered as potential nitrogen cycling prospects. Introduction Historically, gas-condensate reservoirs which exhibit liquid loss through retrograde condensation with reduction in reservoir pressure have been depleted under a full or partial pressure maintenance program by injection of dry natural gas. The technology to evaluate and accomplish this is available and well proved. The increased value and the shortage of natural gas, however, has made it generally uneconomic to divert this gas from the sales line to injection for the purpose of maintaining pressure in gas-condensate reservoirs. This paper is concerned with the economic feasibility. of using cryogenically produced nitrogen as a substitute for natural gas to maintain reservoir pressure during cycling operations in gas-condensate reservoirs. Many factors affect the economics of a gas cycling project. Generally, the three most important factors are prices, stock-tank liquid content of the reservoir gas, and the degree of reservoir heterogeneity. For the purpose of this evaluation, a hypothetical reservoir has been defined. Projections of performance have been made assuming the reservoir contains three different reservoir fluids with stocktank liquid contents ranging from 76.1 to 220.7 bbl/MMcf. The performance of each of these reservoir fluid systems has been evaluated assuming three different degrees of reservoir heterogeneity. Performance and economic projections have been made assuming three different depletion methods:pressure depletion with no injection,pressure maintenance by nitrogen injection, andpressure maintenance by return of residue gas and purchase of makeup gas. Multiple projections have been made for the injection cases assuming blowdown of the reservoir is initiated at various times, starting with breakthrough of dry gas. Performance and economic results are presented for those cases which produce the maximum income discounted at a rate of 15070 per year. Economic evaluations were made assuming prices and costs escalate at a rate of 6070 per year. Projections of Performance Reservoir Description To make an economic evaluation of cycling a gas-condensate reservoir with nitrogen, it was necessary to obtain projections of reservoir performance. It was our desire to evaluate the effect of different reservoir fluid compositions and degrees of reservoir heterogeneity upon the economic potential of this depletion mechanism. To isolate these effects, performance projections were made on a hypothetical reservoir whose properties are shown in Table 1. The hypothetical field contained six contiguous five-spot patterns of 360 acres each. This resulted in a conforming area under injection operations of 2,160 acres or 75070 of the total field area. In all injection cases investigated there were six injection and 12 producing wells. Under pressure depletion it was assumed that there were 18 producing wells. Reservoir Fluid Properties The compositions and basic properties of the three reservoir fluids investigated are presented in Table 2. Reservoir Description To make an economic evaluation of cycling a gas-condensate reservoir with nitrogen, it was necessary to obtain projections of reservoir performance. It was our desire to evaluate the effect of different reservoir fluid compositions and degrees of reservoir heterogeneity upon the economic potential of this depletion mechanism. To isolate these effects, performance projections were made on a hypothetical reservoir whose properties are shown in Table 1. The hypothetical field contained six contiguous five-spot patterns of 360 acres each. This resulted in a conforming area under injection operations of 2,160 acres or 75070 of the total field area. In all injection cases investigated there were six injection and 12 producing wells. Under pressure depletion it was assumed that there were 18 producing wells. Reservoir Fluid Properties The compositions and basic properties of the three reservoir fluids investigated are presented in Table 2.

Model Studies of Oil Displacement from Thin Sands by Vertical Water Influx from Adjacent Shales

Abstract In reservoirs containing soft shales interbedded with oil-producing sands, it is possible to have water movement from the shales into the sands during reservoir depletion. This paper presents the results of scaled flow-model tests performed to investigate the efficiency of oil displacement by this vertical influx of water into oil-producing sands. In these model tests, the effects of rate of influx and rock wettability were considered. Oil recoveries by shale-water influx and by water flooding were compared after 0.4 hydrocarbon volume of water entered the producing sand. This comparison was made for water-wet and oil-wet systems. In water-wet sand, shale-water influx produces slightly less oil than conventional water flooding; in oil-wet sand, shale-water influx produces about one-half as much oil as conventional water flooding. In another type of comparison, it was found that shale-water influx followed by water flooding recovers less oil than water flooding alone. This is true for both water-wet and oil-wet sands. A comparison of tests run at different rates of shale-water influx shows that oil recovery is insensitive to rate in water-wet sand; in oil-wet sand, oil recovery decreases with decreasing rate of influx. Introduction Localized subsidence of the earth's surface has accompanied the depletion of some oil reservoirs, particularly in California, along the Texas Gulf Coast, and in the Bolivar Coastal fields of Venezuela. Subsidence occurs when fluid withdrawals reduce the pressure in the reservoir. The reasons for subsidence accompanying a reduction in reservoir pressure are not known with certainty. However, there is considerable evidence that compaction of soft shale beds adjacent to producing oil sands can be a major cause of this subsidence. When the shales compact, a limited amount of water moves from the shales into the producing sands. A schematic illustration of this oil-producing mechanism is shown in Fig. 1. As the pressure in the sand declines due to oil production, a predominantly vertical pressure gradient develops at the sand-shale boundary. This causes water to move from the shale into the sand as indicated by the solid arrows. This paper reports the results of scaled flow-model tests to investigate the efficiency of oil displacement by the vertical influx of shale water into producing sands.