Reservoir Engineering Parameters Research Articles

Underground Hydrogen Storage in Porous Media: The Potential Role of Petrophysics

The objective of this study is to showcase the key geological and reservoir engineering parameters that influence underground hydrogen storage, demonstrate the value of some petrophysical data, and show how hydrogen storage differs between depleted gas fields and saline aquifers for reservoir and geomechanical modeling. We utilized numerical simulation modeling to create a base-case model of a synthetic reservoir that accurately represented the hydrodynamic conditions relevant to underground hydrogen storage in porous media. A two-step sensitivity analysis was then conducted. Firstly, we identified the critical parameters that significantly influence the storage and flow of hydrogen in porous media. Subsequently, we analyzed the geomechanical impact of underground hydrogen storage. In addition, we compared the behavior of hydrogen storage to natural gas storage. The study showed that the reservoir depth or current pressure, the reservoir dip, and the flow capacity were the top three factors impacting the optimal withdrawal of hydrogen. The study also revealed that rock displacement and stress changes were important to be monitored, while changes in strain were not significant. If it is assumed that injection occurs in a critically stressed rock, hydrogen injection and withdrawal in saline aquifers could result in more incidence of microseismicity compared to hydrogen storage in depleted fields or even gas storage in depleted fields. This study quantifies uncertainties in data and pinpoints areas where petrophysical measurements could minimize the uncertainty associated with critical parameters relevant to underground hydrogen storage. It also identifies gaps in measurements for hydrogen storage in porous media. These parameters with large uncertainty are crucial for selecting optimal sites for hydrogen storage and detecting subsurface integrity issues when monitoring for underground hydrogen storage in porous media.

Research on Displacement Efficiency by Injecting CO2 in Shale Reservoirs Based on a Genetic Neural Network Model

Carbon dioxide injection can help solve two issues in shale reservoir production. Firstly, it can reduce carbon emissions while, secondly, improving unconventional reservoir recovery. There are many controlling factors for CO2 injection to enhance oil recovery in shale reservoirs, and the effect of field implementation varies greatly. The key to popularizing this extraction technology is determining the main controlling factors of CO2 displacement efficiency. Using CO2 shale displacement laboratory results, the grey correlation analysis method was used to determine the main controlling factors affecting core oil displacement efficiency, such as shale reservoir physical parameters (rock compressibility, porosity, median pore size, matrix permeability, TOC, and oil saturation) and engineering parameters (soaking time and injection pressure). The genetic algorithm (GA) was introduced to optimize the backpropagation (BP) neural network to construct the prediction model of the CO2 indoor displacement experiments in shale cores. The results showed that the injection pressure among the engineering parameters, the CO2 soaking time among the gas injection parameters, and the porosity among the shale physical parameters were the main controlling factors affecting the oil displacement efficiency. The prediction accuracy of the genetic neural network model improved, and the coefficient of determination (R2) reached 0.983. Compared with the conventional neural network model, the mean absolute error (MAE) was reduced by 30%, the root mean square error (RMSE) was reduced by 46%, and the R2 increased by 11%. Optimizing the learning and training of the prediction model significantly reduces the cost of laboratory experiments. The deep-learning model completed by training can intuitively show the degree of influence of input parameters on output parameters, providing a theoretical basis for the study of CO2 displacement mechanisms in shale reservoirs.

A method for evaluating resource potential and oil mobility in liquid-rich shale plays—An example from upper Devonian Duvernay formation of the Western Canada Sedimentary Basin

This paper discusses methods of assessing oil and gas resources and evaluating their mobility in shale reservoirs using programed pyrolysis data in conjunction with reservoir engineering parameters derived from production data. The hydrocarbon resource is calculated from the measured free hydrocarbon by programed pyrolysis with correction of evaporative loss that occurred during coring, storage and sample preparation. The correction takes account of the loss of light hydrocarbon fluids as a result of phase change during core retrieval to the surface and evaporative loss related to storage and sample preparation. Based on their response to ramping temperature during sample pyrolysis and thermal equilibrium behavior of distinct petroleum products at different thermal maturities, the estimated oil and gas resources are divided into three categories: non-movable, restricted, and movable to characterize the mobility of the petroleum fluids. The mobility classification is compared with oil compositional grouping based on evaporative kinetics of petroleum products in rock samples to examine their affinity. Pyrolysis analysis results from naturally matured samples and production data from different fluid zones in the Duvernay Shale resource play in Western Canada Sedimentary Basin (WCSB) were used to demonstrate the application of the proposed method. While the mobility of petroleum fluids increases with thermal maturation in general, the total movable resource reaches its maximum at the end of oil generation window, then declines as a result of massive loss due to hydrocarbon expulsion towards to gas window where liquids are thermally cracked to gaseous hydrocarbons. Compositional grouping based on evaporative kinetics does not show a complete accordance with mobility grouping, suggesting composition is only one of many factors affecting hydrocarbon fluid flow in shale reservoir. More studies are required to better understand the fundamentals of oil mobility in shale reservoir.

Application of CO2 miscible flooding in ultra-low permeability beach-bar sand reservoir

The beach-bar sand reservoir of the Sha 4 Member of the Shahejie Formation in the Dongying Sag is the main oil-bearing formation in this area. In recent years, its proven reserves have been getting lower and lower, and the poor petrophysical properties of the reservoir have made water injection development difficult. In turn, it results in a rapid decline in elastic development productivity and low oil recovery. In this study, the experimental evaluation and numerical simulation research on the adaptability of CO2 flooding in beach-bar sand reservoirs are carried out on the basis of fully investigating the successful examples of CO2 flooding conducted by the previous. According to the geological characteristics of the reservoir in the CL area of the Dongying Sag, the reasonable reservoir engineering parameters and surface injection procedures for the CO2 flooding have been formulated. Experiments show that after the completion of water flooding, the recovery factor of the CO2 continuous flooding is 85.64%. It proves that the recovery factor of the CO2 flooding is higher than that of the water flooding. Field tests have shown that CO2 molecules in beach-bar sand reservoirs behave in a supercritical state underground, which is easier to being injected into the reservoir than water. In addition, the displacement distance of the CO2 is obviously larger than that of the water injection development. The gas-oil ratio variation of different flooding types is different, and CO2 flooding can effectively increase the formation energy, and improve the oil recovery and economic benefits of this type of reservoir.

Interplay of large-scale tectonic deformation and local fluid injection investigated through seismicity patterns at the Reykjanes Geothermal Field, Iceland

SUMMARY Occurrence of seismicity sequences as consequence of fluid injection or extraction has long been studied and documented. Causal relations between injection parameters, such as injection pressure, injection rates, total injected volumes and injectivity, with seismicity derived parameters, such as seismicity rate, cumulative seismic moment, distance of seismicity (RT-plot), b-values, etc. have been derived. In addition, reservoir engineering parameters such as permeability/porosity relations and flow types play a role together with geology knowledge on fault and fracture properties, influenced by the stress field on different scales. In this paper, we study observed seismicity related to water injection at the Reykjanes Geothermal Field, Iceland. The region near the injection well did not experience seismicity before the start of injection. However, we observed continued seismic activity during the 3 months of injection in 2015, resulting in a cloud of about 700 events ranging in magnitude from Mw 0.7 to 3.3. We re-located these events using a modified double-difference algorithm and determined focal mechanism of event subsets. Characteristic for the site is that the events are bound to about 4 km distance to the injection point, and moreover known faults seem to act as barrier to fluids and seismicity. Several repeating sequences of seismicity, defined as bursts of seismicity have hypocenter migration velocities larger than 4 km d–1 and their dominant direction of propagation is away from the injection point towards larger depths. The seismic events within the bursts lack larger magnitude events, have elevated b-values (∼1.5) and consist of many multiplets. Except from the coinciding onset of seismicity with the start of fluid injection, no correlation between injection rates and volumes could be identified, neither could hydraulic diffusivity models explain observed seismicity patterns. Comparison of our results with investigations on background seismicity from 1995 to 2019 and from a seismic swarm in 1972 revealed similar focal mechanism patterns and burst-like seismicity patterns. We finally present a conceptual model where we propose that the observed seismicity patterns represent a stress release mechanism in the area close to the injection well, controlled by an interplay of local pore pressure and stress field changes with continued extensional stress build up at the Reykjanes Ridge.

Technologies and practice of CO2 flooding and sequestration in China

Abstract The latest advancement of CO2 flooding and sequestration theory and technology in China is systematically described, and the future development direction is put forward. Based on the geological characteristics of continental reservoirs, five theories and key technologies have been developed: (1) Enriched the understandings about the mass transfer characteristics of components between CO2 and crude oil in continental reservoirs, micro-flooding mechanism and sequestration mechanism of different geological bodies. (2) Established the design method of reservoir engineering parameters, injection-production control technology and development effect evaluation technology of CO2 flooding, etc. (3) Developed a series of production engineering technologies such as separated layer CO2 injection technology, high efficiency lifting technology, on-line wellbore corrosion monitoring and protection technology. (4) Innovated a series of surface engineering technology including CO2 capture technology, pipeline CO2 transportation, CO2 surface injection, and production gas circulation injection, etc. (5) Formed a series of supporting technologies including monitoring, and safety and environmental protection evaluation of CO2 flooding reservoir. On this basis, the technological development directions in the future have been put forward: (1) Breakthrough in low-cost CO2 capture technology to provide cheap CO2 gas source; (2) Improve the miscibility technology between CO2 and crude oil to enhance oil displacement efficiency; (3) Improve CO2 sweeping volume; (4) Develop more effective lifting tools and technologies; (5) Strengthen the research of basic theory and key technology of CO2 storage monitoring. CO2 flooding and sequestration in the Jilin Oilfield shows that this technology has broad application prospects in China.

The application of modified isochronal well test in a low-permeability condensate gas field

ABSTRACTThe modified isochronal well test is a deliverability test method suitable for gas wells in low-permeability gas reservoirs. Generally, the absolute open flow of gas wells is determined by modified isochronal well test, thereby establishing a reasonable working system for gas wells. It is also possible to obtain gas layer physical parameters, gas reservoir engineering parameters, heterogeneity, boundary characteristics, etc. In this paper, the actual test data of a condensate gas field are applied. By modified isochronal well test analysis, not only the deliverability equation of the gas well is obtained, but also the absolute open flow is determined. At the same time, the formation parameters such as reservoir permeability and skin factor are obtained and the acidification effect is evaluated.

Environmental and Operational Performance of CO2-EOR as a CCUS Technology: A Cranfield Example with Dynamic LCA Considerations

This study evaluates the potential of carbon dioxide-enhanced oil recovery (CO2-EOR) to reduce greenhouse gas emissions without compromising oil production goals. A novel, dynamic carbon lifecycle analysis (d-LCA) was developed and used to understand the evolution of the environmental impact (CO2 emissions) and mitigation (geologic CO2 storage) associated with an expanded carbon capture, utilization and storage (CCUS) system, from start to closure of operations. EOR operational performance was assessed through CO2 utilization rates, which relate usage of CO2 to oil production. Because field operational strategies have a significant impact on reservoir engineering parameters that affect both CO2 storage and oil production (e.g., sweep efficiency, flood conformance, fluid saturation distribution), we conducted a scenario analysis that assessed the operational and environmental performance of four common and novel CO2-EOR field development strategies. Each scenario was evaluated with and without stacked saline carbon storage, an EOR/storage combination strategy where excess CO2 from the recycling facility is injected into an underlying saline aquifer for long-term carbon storage. The dynamic interplay between operational and environmental performance formed the basis of our CCUS technology analysis. The results showed that all CO2-EOR evaluated scenarios start operating with a negative carbon footprint and, years into the project, transitioned into operating with a positive carbon footprint. The transition points were significantly different in each scenario. Water-alternating-gas (WAG) was identified as the CO2 injection strategy with the highest potential to co-optimize EOR and carbon storage goals. The results provide an understanding of the evolution of the system’s net carbon balance in all four field development strategies studied. The environmental performance can be significantly improved with stacked storage, where a negative carbon footprint can be maintained throughout the life of the operation in most of the injection scenarios modelled. This information will be useful to CO2-EOR operators seeking value in storing more CO2 through a carbon credit program (e.g., the 45Q carbon credit program in the USA). Most importantly, this study serves as confirmation that CO2-EOR can be operationally designed to both enhance oil production and reduce greenhouse gas emissions into the atmosphere.

Investigating the Impact of Reservoir Properties and Injection Parameters on Carbon Dioxide Dissolution in Saline Aquifers

CO2 injection into geological formations is considered one way of mitigating the increasing levels of carbon dioxide concentrations in the atmosphere and its effect on and global warming. In regard to sequestering carbon underground, different countries have conducted projects at commercial scale or pilot scale and some have plans to develop potential storage geological formations for carbon dioxide storage. In this study, pure CO2 injection is examined on a model with the properties of bunter sandstone and then sensitivity analyses were conducted for some of the fluid, rock and injection parameters. The results of this study show that the extent to which CO2 has been convected in the porous media in the reservoir plays a vital role in improving the CO2 dissolution in brine and safety of its long term storage. We conclude that heterogeneous permeability plays a crucial role on the saturation distribution and can increase or decrease the amount of dissolved CO2 in water around ± 7% after the injection stops and up to 13% after 120 years. Furthermore, the value of absolute permeability controls the effect of the Kv/Kh ratio on the CO2 dissolution in brine. In other words, as the value of vertical and horizontal permeability decreases (i.e., tight reservoirs) the impact of Kv/Kh ratio on the dissolved CO2 in brine becomes more prominent. Additionally, reservoir engineering parameters, such as well location, injection rate and scenarios, also have a high impact on the amount of dissolved CO2 and can change the dissolution up to 26%, 100% and 5.5%, respectively.

Dynamic impact and flow-based upscaling of the estuarine point-bar stratigraphic architecture

Abstract The estuarine point-bar architecture – one of the main sub-depositional environments of tide-dominated shallow-marine and fluvial (SM&F) systems – constitutes one of the most shale-prone clastic reservoir architectures potentially posing risks to the production performance. A set of simulation-based sensitivity studies quantify the effects of a number of stratigraphic and reservoir engineering parameters on the dynamic connectivity of the confined estuarine point-bar architecture. Water injection recovery mechanism is utilized for polarizing the stratigraphic and reservoir engineering parameters in terms of their effects on hydrocarbon recovery. The point-bar shale-drape architecture and abandonment channel attributes (e.g., permeability, facies composition, and shale-drape coverage) dominate the dynamic reservoir connectivity, hence the recovery factor and water breakthrough time/profile. In terms of reservoir engineering parameters, well spacing and, to some degree, relative mobility ratio constitute the factors of importance for the investigated model parameter ranges. The dynamic effects of intra-facies permeability heterogeneity are evaluated using a number of realizations comparing them to those stemming from facieswise-homogeneous realizations. Results indicate that intra-facies permeability heterogeneity influences the connectivity factor for low shale-drape coverage levels. For high coverage levels, presence of shale drapes almost completely overshadows the influences of intra-facies permeability heterogeneity. A novel multiphase flow-based upscaling method, specifically developed for clastic reservoirs containing long-correlation-length permeability heterogeneity, is evaluated first-time on the scale-up of the estuarine point-bar architecture. Resulting coarse-scale models capture the fine-scale dynamic behavior with an accuracy level that is significantly higher than those obtained by use of single-phase flow-based upscaling.

The impact of fine-scale turbidite channel architecture on deep-water reservoir performance

This article concentrates on the question, Which parameters govern recovery factor (RF) behavior in channelized turbidite reservoirs? The objective is to provide guidelines for the static and dynamic modeling of coarse reservoir-scale models by providing a ranking of the investigated geologic and reservoir engineering parameters based on their relative impact on RF. Once high-importance (H) parameters are understood, then one can incorporate them into static and dynamic models by placing them explicitly into the geologic model. Alternatively, one can choose to represent their effects using effective properties (e.g., pseudorelative permeabilities). More than 1700 flow simulations were performed on geologically realistic three-dimensional sector models at outcrop-scale resolution. Waterflooding, gas injection, and depletion scenarios were simulated for each geologic realization. Geologic and reservoir engineering parameters are grouped based on their impact on RF into H, intermediate-importance (M), and low-importance (L) categories. The results show that, in turbidite channel reservoirs, dynamic performance is governed by architectural parameters such as channel width, net-to-gross, and degree of amalgamation, and parameters that describe the distribution of shale drapes, particularly along the base of channel elements. The conclusions of our study are restricted to light oils and relatively high-permeability channelized turbidite reservoirs. The knowledge developed in our extensive simulation study enables the development of a geologically consistent and efficient dynamic modeling approach. We briefly describe a methodology for generating effective properties at multiple geologic scales, incorporating the effect of channel architecture and reservoir connectivity into fast simulation models.

Evaluation of low amplitude and low resistivity pay zones under the fresh drilling mud invasion condition

Abstract Low amplitude and low resistivity oil reservoirs are developed in the Triassic Chang 2 oil layers in A block of Changqing Oilfield. They are controlled by palaeogeomorphology, have large oil-bearing areas, and may form large-scale low resistivity reservoirs. The petrophysical origin study of the reservoirs reveals that the main reasons for low resistivity are the low oil saturation caused by the gentleness of the structure, and the different influences of fresh drilling mud filtrate invasion on dual induction logging in oil pay and water zones. A step-by-step logging identification and quantitative evaluation method was established. Through the three steps of conventional logging cross-plot, invasion factor analysis based on the invasion principle, and comparison between wells, pay zones can be effectively identified and the ability of logging interpretation is enhanced. A quantitative evaluation of oil reservoirs can be made by the forward modeling of the fresh drilling mud invasion, the inverse interpretation under the constraint conditions of geological and reservoir engineering parameters, and the quantitative evaluation result verification, thus improving the accuracy and reliability of logging identification and quantitative evaluation of low resistivity pay zones in low amplitude reservoirs.

Optimizing Recovery for Waterflooding Under Dynamic Induced Fracturing Conditions

Summary It is well established within the industry that water injection mostly takes place under induced fracturing conditions. Particularly in low-mobility reservoirs, large fractures may be induced during the field life. This paper presents a new modeling strategy that combines fluid flow and fracture growth (fully coupled) within the framework of an existing "standard" reservoir simulator. We demonstrate the coupled simulator by applications to repeated five-spot pattern flood models, addressing various aspects that often play an important role in waterfloods: shortcut of injector and producer, fracture containment to the reservoir layer, and areal and vertical reservoir sweep. We also demonstrate how induced fracture dimensions (length, height) can be very sensitive to typical reservoir engineering parameters, such as fluid mobility, mobility ratio, 3D saturation distribution (in particular, shockfront position), 3D temperature distribution, positions of wells (producers, injectors), and geological details (e.g., layering and faulting). In particular, it is shown that lower overall (time-dependent) reservoir transmissibility will result in larger induced fractures. Finally, it is demonstrated how induced fractures can be taken into account to determine an optimum life-cycle injection rate strategy. The results presented in this paper are expected to also apply to (part of) enhanced-oil-recovery operations (e.g., polymer flooding).

Role of Asphaltenes in Foamy Oil Flow

Abstract It has been suggested in several studies that there may be a link between the presence of high asphaltenes content and the foam-ability of oil. However, a systematic examination of the impact of asphaltenes on the performance of solution gas drive, in connection with foamy oil flow, has not been reported. This paper presents an experimental study that addresses this issue. The objective of this work was to examine whether or not the presence of asphaltenes has a strong influence on the performance of foamy solution gas drive. To this end, parallel solution gas drive experiments were conducted using a heavy crude oil from the Lloydminster area and a deasphalted version of the same oil. To eliminate the influence of oil viscosity, the viscosity of the crude oil was reduced to the same level as that of the deasphalted oil by diluting it with a 50–50 mixture of heptanes and toluene. The experiments were carried out in a visual sandpack that permits observation of bubble formation in the sand. The results show that the presence of asphaltenes significantly promotes foamy oil flow. Introduction Noticeable progress in understanding the high efficiency of solution gas drive in heavy oil reservoirs has been made in recent years. However, basic mechanisms and reservoir engineering parameters are still being evaluated(1). Some authors attribute the high efficiency of solution gas drive in heavy oil reservoirs to foam, and the term foamy oil is used to describe the process. The question of how the foam forms and how it helps in improving the production performance remains to be fully answered. In order to explain this high primary production, two main mechanisms have been proposed(1, 2). The first is the increase of the drainage radius of the well by the formation of high permeability channels, called wormholes(3). The second mechanism is the low gas mobility in heavy oil leading to gas retention that helps in maintaining high pressures in the reservoirs. Low gas mobility is explained by the high oil viscosity and its foamy nature. Smith(4) was the first to propose a model in which the gas flow was in the form of micro bubbles dispersed in the oil phase. Subsequently, Maini et al.(5) experimentally observed this dispersed gas phase and called it Foamy Oil. This leads to the discussion of how the foam is formed and its nature, stability and movement in the formation rock. Although the foamy oil flow occurs in all viscous oil systems, irrespective of whether or not the oil contains asphaltenes, it has been suggested that asphaltenes enhance foaminess. Claridge and Prats(6) proposed that bubble stability is related to the asphaltenes adsorption at the gas-oil interface, which protects bubbles against coalescence. However, experimental results on the effect of asphaltenes are conflicting. In micromodel experiments, Bora et al.(7) observed that asphaltenes lower coalescence rates. Tang and Firoozabadi(8) did not observe any differences in comparing crude oil and silicon oil with similar viscosity. Other authors have suggested that foaming and surface properties of crude oils change with the asphaltenes concentration(9–12).

Recent Advances In Coring Technology: New Techniques to Enhance Reservoir Evaluation And Improve Coring Economics

Abstract Damage to core during acquisition and handling, as well as the high cost of some coring operations, have been major issues confronting the coring and core analysis industry. Core damage leads to analytical difficulties in the laboratory which can compromise the reliability of core analysis. It is necessary to conduct tests on undamaged core, because major reservoir evaluation issues and reserves estimates can be dependent 'on core-based data. The overall cost of coring is influenced more by rig time rather than direct charges for coring services. A dramatic drop in the number of cores being cut by operators over the last 10 years demonstrates industry's perceived value of core analysis. Two new tools, gel coring and coring while drilling (CWD), have been developed to provide geoscientists, reservoir engineers and drilling engineers with options to improve reservoir evaluation and reduce coring costs. Downhole core preservation and encapsulation using high viscosity gel is an alternative to operator-intensive, wellsite core preservation. Standard downhole coring assemblies do not, preserve in situ reservoir properties because no provisions are made for core preservation prior to core surfacing. Low invasion coring systems help minimize drilling fluid invasion, but rock wettability and fluid saturations can still be altered by counter-current imbibition of mud filtrate and/or diffusion before core analysis begins. Core gel is a viscous, high molecular weight, polypropylene, glycol with zero spurt loss, which is non-soluble in water and environmentally safe. Because the Gel comes in direct contact with the core during and immediately after it is cut, further exposure to core contaminants is minimized. The high viscosity gel stabilizes poorly consolidated rocks with moderate compressive strengths and enhances core-integrity. Core gels can be customized to address most coring situations and rock types. The coring while drilling (CWD) system is designed to provide operators with the flexibility of bottomhole coring or drilling with the same bit, without tripping-out of the borehole. In the drilling mode, the system is used in the same manner as a conventional bottomhole assembly (BRA). In the coring mode, a drill bit plug is replaced with an inner barrel and bearing assembly that transforms the drill bit into a core bit. After core recovery, the coring assembly is retrieved with a wireline and overshot assembly. Additional cores are cut or the retrievable drill (plug is quickly reconfigured for drilling ahead. CWD uses high-rate of penetration (ROP) anti-whirl polycrystalline diamond compact (PDC) bits and significantly reduces the time necessary to cut continuous full-diameter cores. The CWD system excels when core depths cannot be determined a priori and where thick non-reservoir sections separate zones of interest. Gel Coring Drilling fluid filtrate invasion during coring can add uncertainty to the interpretation of core analysis results and may preclude fresh-state testing. In particular, in situ rock wettability can be altered by drilling fluid components and affect critical petrophysical and reservoir engineering parameters, e.g., residual fluid saturations, Archie saturation exponent "n," and relative permeability.

Characterization of Reservoir Boundaries Using Interference Tests.

Boundary effects in the pressure-transient tests offer an excellent opportunity to provide information about reservoir engineering parameters and to characterize reservoir boundary conditions such as, sealing fault versus nonsealing fault.This paper investigated transient pressure for a water-drive reservoir with irregularly shaped boundaries. The paper applied the image-well method to interpret a field interference test and to characterize reservoir boundaries. This paper also interpreted a field interference test in an anisotropic aquifer to identify the recharging boundaries.

Predicting Pressure Distribution in Irregularly Shaped Reservoirs under Water-drive Conditions.

Many analytical methods use radial and rectangular systems to interpret unsteady-state reservoir flow problems. However, there is no information currently available for irregularly shaped water-drive reservoirs. For many practical cases the reservoir drainage shape is too complicated to be approximated by a circular or rectangular shape. In addition, many reservoirs are under water-drive conditions. This paper develops a means of predicting pressure-transient behavior in an irregularly shaped water-drive reservoirs.In this paper, the dimensionless-pressure function is obtained by superposing the line-source solutions of image wells in time. The method is first applied to regularly shaped reservoirs under water-drive conditions. The validity of the approach is then proved by comparison of the calculated dimensionlesspressure functions with literature values for various regular drainage shapes. The proven technique could be used to analyze the field pressure-transient data to provide information on reservoir engineering parameters, water-drive distribution and strength, fault sealingness and non-sealingness.

The Larderello geothermal field: a review

This paper reviews published geological, geophysical, petrological and geochemical data, together with reservoir engineering parameters, of the Larderello geothermal reservoir of southern Tuscany, Italy. Some theories are proposed on the deep origin, evolution in time, and natural state of this geothermal field prior to its exploitation. The interaction between the vapor-dominated reservoir and surrounding aquifers is discussed. Analysis of hydrogeochemical data suggests that meteoric waters from shallow external aquifers contribute little to the production of steam. The vapor-dominated system and the cold external aquifers are separated by areas of very low permeability where physical conditions change greatly over short distances. The presence and significance of liquid phases in the peripheral areas of the vapor-dominated reservoir are interpreted as being due to steam condensation. The latter is a consequence of: (a) low permeability conditions in the deep buried parts of the carbonate reservoir formations in the north-northwestern sector of the field, and (b) by the mixing of ascending superheated steam from depth with cold CaSO 4 meteoric waters circulating in unconfined shallow aquifers within the outcrops of the carbonate reservoir formations in the south-southeastern parts of the field. The presence of steam below these liquid-dominated sectors of the reservoir seems possible. The limited natural recharge of the system, the constant steam production rate for geothermal power generation (3000 t h −1, since 1951), the persistence of natural thermal features, and the fact that reinjection has had little effect on the characteristics of the fluid discharged, seem to indicate a steady state for the Larderello field. The main contribution to production seems to be from superheated steam ascending from depth and the in situ evaporation of water stored in the small pores of the rocks present in Larderello, in a system that is much larger than the one known at present.

Novel Approach to Sensitivity Analysis

Summary An entropy function is introduced to quantify the uncertainty in reservoir engineering parameters that are represented as random variables and described by probability distributons. When combined with a given algorithm and a Monte Carlo simulation routine, the concept can be used to estimate the degree of certainty required in input variables to yield a given certainty of the output parameters. The method is illustrated with a simplified model for water-alternating gas (WAG) miscible flooding. Two ranking schemes for five input variables are established and compared. The rankings provide an assessment of the overall model response with respect to a base case as related to average value and to degree of certainty of each input variable. Introduction Many reservoir engineering studies rely on data that contain some known or unknown error. Measurements are not always available, and key parameters are often estimated by other means. To account for this uncertainty, quantities can be described by probability distributions. Any parameter dud depends on one or more of these quantities has a probability distribution that is a function of the input probability distributions. Uncertainties often accumulate, leading to variances of output parameters that are unacceptably high. If the overall uncertainty of input variables is reduced, output variances will be lowered. The commitment of manpower and financial resources necessary to achieve this reduction, however, can be substantial. It is important, therefore, to estimate a priori the amount of reduction in uncertainty required for each input parameter to obtain a given increase in output certainty currently used sensitivity analyses do not yield this information. Combining an entropy function with a Monte Carlo simulation approach yields a new method that provides these estimates. S Value The notion of entropy, originally introduced in its differential form as S= /T in thermodynamics, has been successfully applied in other fields as a measure of randomness or disorder. In statistical physics, if quantilies the closeness of a system to equilibrium and plays a central role in describing the thermodynamic properties of ideal gases. In communication theory, it specifies the average amount of information transmitted per symbol. It is used in ergodic theory as a characterization of partitions and measure-preserving transformations. In terms of the underlying measure space, is defined similarly for all three cases.