Reservoir Engineering Aspects Research Articles

Study Reviews Reservoir Engineering Aspects of Geologic Hydrogen Storage

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23943, “Reservoir Engineering Aspects of Geologic Hydrogen Storage,” by Johannes F. Bauer, Mohd M. Amro, SPE, and Taofik Nassan, SPE, Technical University Bergakademie Freiberg, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. Reproduced by permission. _ Safe and effective large-scale storage of hydrogen (H2) is one of the greatest challenges of the global energy transition and can be realized only through storage in geological formations. The aim of the study detailed in the complete paper is to address and discuss the reservoir engineering aspects of geological H2 storage (GHS). The study is based on two sources: first, a comprehensive literature review and, second, experimental and numerical work performed by the authors’ institute. H2 Pressure/Volume/Temperature (PVT)/Phase Behavior The definition of the PVT/phase behavior of reservoir fluids is crucial in GHS because thermodynamic properties significantly affect safety and effectiveness. The properties of H2 are widely known and modeled, but its reaction with other gases, such as in-situ gases like natural gas in depleted gas reservoirs (DGR), currently is under investigation. Although the ideal gas law can account for H2 behavior at low pressure, accurate depiction of its thermodynamic properties requires more-sophisticated equations of state (EOS), especially when it is mixed with other gases such as methane. Most commercial reservoir simulators use EOS packages that can model the complex properties of these mixtures, mostly within required reliability. In most instances, calibration is still required if experimental PVT data are available. Reservoir Engineering of GHS. GHS projects must meet three crucial technical benchmarks for underground storage: capacity (storage volume), injectivity/productivity (rate of injection/withdrawal in relation to wellhead pressure), and containment integrity (prevention of leakage). Economic sustainability requires that projects must adhere to these standards, which may vary according to the selected geological formations. Although various subsurface structures can store H2, only specific formations such as salt caverns (SCs), saline aquifers (SAs), and depleted gas/oil reservoirs (DGRs and DORs), fulfill the requirements. While the complete paper discusses all three of these formation types in detail, this synopsis will concentrate on SCs. GHS in SCs. SC storage typically involves up to three wells for one cavern with a volume of up to 500,000 std m3, providing a delivery rate of 8,500–17,000 std m3/day. Working gas accounts for up to 65% of the total gas, while water should be kept to a minimum. SCs usually allow between six and 12 operating cycles per year, each lasting approximately 10 days for withdrawal periods. SCs offer high H2 purity and sealed storage. The storage capacity of caverns in Germany is determined by their volume and pressure limitations while avoiding any negative geomechanical effects. These caverns can range in depth from 500 to 2000 m, with heights of up to 400 m. Approximately 30 to 50% of the total stored volume is used as cushion gas to maintain production pressure. Estimating the capacity of these caverns relies on their geometry and thermodynamics, resulting in relatively lower uncertainties when compared with storages in porous media.

Hydrogen Storage in Porous Rocks: A Bibliometric Analysis of Research Trends

Currently, there is an increasing number of research studies on underground storage of hydrogen in porous rocks (aquifers and depleted hydrocarbon fields). An important aspect of this process is the efficiency of hydrogen storage, which is defined as the correct operation of a storage facility (the ability to inject and withdraw an appropriate quantity of gas) and the safety of storage, which is influenced by numerous factors, including geological factors. With an increasing number of publications, gathering knowledge and keeping track of scientific progress is becoming increasingly complex. In addition to the technical interdependence of the parameters analysed, there are also interrelationships between scientific publications addressing issues related to underground hydrogen storage in porous rocks. The aim of this paper is to analyse the literature on hydrogen storage efficiency in porous rocks and, on the basis of the analysis, to identify the most important research trends and issues relevant to their implementation. This article presents an analysis of publications indexed in the SCOPUS database. The analysis included publications that contained expressions related to the relevant search phrases in their title, abstract or keywords. The dynamics of changes in the interest of researchers on the problem of hydrogen storage in porous rocks and the distribution of studies by geographical location (countries) are presented. Based on an analysis of the number of citations, the most influential publications were identified. Using the VOSviewer version 1.6.19 software, clusters reflecting research sub-areas were identified based on co-occurrence analysis, such as geological and reservoir aspects, reservoir engineering aspects, hydrogeological aspects and petrophysical aspects. Bibliometric methods have great potential for performing quantitative confirmation of subjectively delineated research fields and/or examining unexplored areas. The literature on underground hydrogen storage in porous rocks has been growing rapidly since at least 2018, with researchers conducting their studies in four major research streams: geological and reservoir aspects, reservoir engineering aspects, hydrogeological aspects and petrophysical aspects.

Modeling of methane and carbon dioxide sorption capacity in tight reservoirs using Machine learning techniques

The viability of enhanced coalbed methane recovery (ECBM) and enhanced shale gas recovery (ESGR) are abundantly explored in various studies since they present a solution for ongoing energy demand and environmental crisis. As a matter of challenge, the prediction of the gas sorption profile poses a significant obstacle in the development of such resources. In this regard, mathematical models, numerical simulations, empirical correlations, and experimental measurements suffer from over-simplification, computationally extensive calculations, time-consuming, and costly processes. This work examines different machine learning methods, from shallow to deep learning, to investigate their capability to model 3804 data points of methane (CH4) and/or carbon dioxide (CO2) sorption capacity in shale and coal at different thermodynamic conditions. Percentage of CO2 in injection gas, rock type, total organic carbon (TOC), moisture, temperature, and pressure were taken as input. Hyperparameter tuning was executed by Optuna optimizer. According to the results, the random forest (RF) was the most proficient predictor for both test subsets of CH4 (MAE = 0.0864, MSE = 0.0231, RMSE = 0.1520) and CO2 (MAE = 0.0529, MSE = 0.0533, RMSE = 0.2308) sorption capacity. Based on the trend prediction simulation, RF predictors were able to properly capture the single and binary sorption capacities. More importantly, they successfully predict the abnormal descending behavior of CO2 sorption in high pressures. In addition, a sensitivity analysis was carried out to acquire the importance of input features and model hyperparameters in the training process. Input feature impacts were consistent with technical expectations of geology and reservoir engineering aspects. Both models are capable of being applied to lab scale and further developed for their application in reservoir scale simulators.

Evaluating the rock wettability using multi-frequency dielectric measurements: A review on the fundamental concept and experimental approach

The dielectric approach is considered as one of the measurements that have potential in characterizing dissipative mediums which have an electrical contrast in their comprising elements. Recently, there have been remarkable research and development activities aiming to link dielectric responses to different petrophysical properties. Wettability is considered a key parameter in many reservoir engineering aspects including evaluating reservoir performance and designing enhanced oil recovery processes. The rock wettability controls the majority of the electrochemical interactions between the solid grain and the ionically-dissipative fluid. These interactions provide an excellent environment for dielectric measurements to display some dispersion mechanisms under the influence of alternating frequency. This paper presents a comprehensive review on the use of the dielectric approach for wettability evaluation. The majority of the reviewed studies were either a qualitative investigation of this relationship or empirical prediction models for the dielectric measurements based on many inputs which are not available most of the time. Even though significant work has been done in this area, there are still gaps that can be improved and fulfilled. Wettability was still not explored quantitatively through a measurable indicator from the dielectric measurements, for example, no wettability index was developed based on the dielectric approach. Therefore, dielectric could provide an efficient, accurate, and economical wettability index that can be implemented in the industry. Overall, this work aims to review the literature and pave the road for quantifying the wettability index via dielectric measurements.

Recovery efficiency in high-temperature aquifer thermal energy storage systems

Aquifer Thermal Energy Storage (ATES) uses excess thermal energy to heat water which is stored in an aquifer until it is needed, at which time the hot water is recovered and the heat used for some purpose e.g. electricity generation. The recovery efficiency (i.e. the ratio of heat energy recovered to heat energy injected, R) is one of the most important factors dictating the viability of ATES systems.The variation of R with various aquifer properties and operating parameters is explored for high temperature (HT) ATES systems with injection temperatures ≥90∘C, extending the results of previous studies to higher temperatures and a broader range of aquifer properties and operating conditions. R values are calculated using numerical models of a single-well ATES system, which is validated by comparison with previous field and modelling studies.The results show that HT-ATES may be viable with injection temperatures as high as 300 ∘C, depending on the aquifer properties and operating parameters. Daily cycles are very efficient over a broad range of conditions, whereas the efficiency of annual cycles is much more variable. The most important parameters governing R are aquifer thickness, injection temperature, horizontal and vertical permeability, and dispersion length.The R values are used to derive an improved version of the Rayleigh number relationship proposed by Schout et al. (2014), extending the applicability of this relationship to daily cycles and improving its accuracy for annual cycles. An alternative method for estimating R using a convolutional neural network is proposed.The calculated R values may be considered best-case because aspects such as background groundwater flow and geochemical effects are ignored. Practical factors such as energy supply/demand requirements, reservoir and above-ground engineering, financial or regulatory aspects, and public acceptance are not considered. Nevertheless, the results of this study can be used for rapid screening of large areas for potential HT-ATES sites, defining requirements for potential sites, and estimating R values for specific sites, before performing detailed feasibility studies.

Horizontal Wells: Applications, Considerations, and Case Histories

This paper discusses many aspects of the application of horizontal wells for field development, starting with the basic question of why to opt to this technology. The different considerations to be taken into account when dealing with the technology are reviewed, including some inherent downsides like higher cost and operational complications. The main emphasis, however, is placed on practical reservoir engineering aspects, including well planning and performance, and the handling of horizontal wells in specific technical applications like well test
 analysis and numerical modeling.
 
 
 
 The theoretical basis and pertinent differences in physics and flow regimes around vertical and
 horizontal wells are discussed in the context, together with the inherent practical implications.
 Case histories and examples are presented for several successful applications worldwide that the author was involved in. In one case, a medium size field offshore Canada was developed with waterflood utilizing very few horizontal producers, with a set of horizontal and vertical water injectors. Detailed planning and intensive modeling, carried out by a team of engineers and geoscientists, led to a remarkably
 successful field development. In another case, few horizontals were used among many directional wells to develop a Mediterranean oil reservoir under aquifer and gas cap drives in an attempt to reduce coning problems, raising an opportunity to compare the long term performance of different geometry wells.
 A brief description is also presented to some advanced techniques and special cases of implementing horizontal wells such as thermal recovery (Steam-Assisted-Gravity-Drainage, or SAGD Process), multi-lateral wells, and multi-fractured wells, with discussion on these applications. Under favorable conditions, horizontal wells can also be used as an Improved Oil Recovery (IOR) tool in mature fields, an application that became very common in many super giant fields in the Arabian Gulf Area.

Reservoir engineering of in-situ MEOR; impact of microbial community

In this publication, we summarize and discuss the reservoir engineering aspects of applied in-situ MEOR technology. A nutrient formulation was developed to stimulate the targeted microorganisms in terms of its main metabolism with mixed acid fermentation. The incubation radius where the complete consumption of the injected nutrients takes place and the transport of metabolites and bacteria was estimated with well-known reservoir engineering equations, where the growth kinetics as well as retention characteristics were experimentally defined. Spontaneous imbibition experiments supported the contact angle measurements for the change of the wettability from intermediate to oil wet towards water wet. Observations in micromodels showed that bioplugging might be an effective conformance improvement mechanism in heterogeneous reservoirs. These two effects were also confirmed using sandpack and coreflood experiments. The effect of MEOR by the beneficial isolated community (IC) is higher compared to the reservoir community (RC). Therefore, using the IC (as applied mostly) for deciding on the fate of an application can yield overoptimistic conclusions for MEOR. If carbonates make up of even a small portion (1–2 % wt.) of the formation rock composition they act as pH buffers by reducing the negative impacts of a fermentation-induced pH drop and assure continuation of bacterial activity in the reservoir. The dissolution of carbonates as the result of this reaction is another contribution to MEOR causing pore volume increase. The results discussed above have been validated for the specific asset we are working on, for its microbiology, selected N and its reservoir characteristics.

Eagle Ford and Pimienta Shales in Mexico: A Case Study

Summary Our objective in this paper is to highlight the potential of the Eagle Ford (Cretaceous) and Pimienta (Upper Jurassic) shales in Burgos Basin (Mexico) through a comparison with the Eagle Ford Shale in Texas. The comparison is a case study focused on real data and their interpretation, north and south of the border, including geochemistry, geology, production, and reservoir–engineering data. Our overall approach includes the description of Eagle Ford data in Texas, as well as Eagle Ford and Pimienta data in the Burgos Basin. The geologic comparison is carried out using cross sections of the various formations and geophysical data. Geochemical and petrophysical data are compared using specialized crossplots. Production data are compared through rate transient analysis and by investigating the different flow periods observed in wells in both sides of the border. Reservoir–engineering aspects are compared using material–balance methods developed specifically for analyzing multipurpose shale petroleum reservoirs. Results indicate that there are many similarities but also some differences between the Eagle Ford Shale in Texas and shales in Mexico. The geologic and seismic cross sections show that there is continuity of the Eagle Ford on both sides of the border. However, structural geology in Mexico tends to be more complex than that in Texas. The geological and geochemical descriptions also show important similarities in the rock mineralogy, and the quantity, quality, and maturity of the organic matter. Well–log data show the same pattern of distribution on modified Pickett plots, developed originally for evaluation of the Eagle Ford Shale in Texas. Production data in the Burgos Basin shales are characterized by long periods (several months or even years) of transient linear flow, something that compares well with the Eagle Ford in Texas. Specialized material–balance calculations, which consider multiple porosities, have been used in the Eagle Ford Shale in Texas and are shown to have similar application in the Burgos Eagle Ford and Pimienta shales. On the basis of the Eagle Ford Shale performance in Texas, and the similarities with Burgos shales, the conclusion is reached that there is significant potential in the Mexican Eagle Ford and Pimienta shales. We present a comparison of the interpretation of real geoscience and engineering shale data collected on both sides of the border. The comparison is meaningful and suggests that the potential of shale reservoirs south of the border will be quite significant. Mexico should benefit from the lessons learned from the Texas Eagle Ford Shale.

A Practical Simulation Method Capturing Complex Hydraulic-Fracturing Physics

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 172831, “Forecasting Production in Shale and Tight Reservoirs: A Practical Simulation Method Capturing the Complex Hydraulic-Fracturing Physics,” by Axelle Baroni, Matthieu Delorme, and Nina Khvoenkova, IFP Energies nouvelles, prepared for the 2015 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 8–11 March. The paper has not been peer reviewed. To understand production from shale reservoirs, the role of hydraulically induced fractures, natural fractures, and their interaction in a formation must be captured. Implementation of such approaches is data-intensive and is accurate only when the field is fully characterized. A model has been developed in which fractures are discretized explicitly and flow is coupled by use of simplified mechanics. It can be considered as an intermediate method between a fully developed discrete-fracture-network (DFN) model and simplified hydraulic-fracturing models. Introduction The current view is that many unconventional reservoirs comprise well-developed natural-fracture networks with multiple orientations within which complex hydraulic-fracture patterns develop, as suggested by microseismic data. The unconventional-reservoir modeling process follows a multidisciplinary integrated approach that includes specific aspects of geophysics, geology, laboratory work, and reservoir engineering. To understand the shale-deformation processes, the flow should be coupled with mechanics, yet the complexity of the involved mechanisms governing stimulation modeling precludes very fast simulations. Characterizing all parameters is a challenge because of the uncertainty of natural- fracture distribution, potential local stress changes, and the lack of reservoir description in three dimensions. The best practice able to capture the most-important phenomena, integrating while being accurately predictive, is not yet defined. The presented work flow (detailed in Fig. 1 and in the text of the complete paper) focuses on the entire stimulation process, describing a simplified yet physically sound model in a 3D discrete and deformable fracture network (DDFN). Flow Methodologies The first step of the work flow is the natural-fracture- network characterization. By use of image and classical logs coupled with other seismic and geological analysis, the natural-fracture model can be constructed. The overall fracture network (natural and hydraulically induced fractures) is defined by one or several fracture families, each being defined deterministically (faults and damaged zone) or by statistical laws (hydraulically induced and natural fractures) for orientation, density, and size. Overall connectivity and fracture hydraulic properties are more uncertain than geometrical ones, usually calibrated from dynamic data. By use of the fracture families’ statistical properties, the discrete network can be generated stochastically (depending on the random seed). Each perforation “shot” is represented by a highly conductive near-well damaged zone of a few meters.

Reservoir Engineering Aspects of Pilot Scale CO2 EOR Project in Upper Mississippian Formation at Wellington Field in Southern Kansas

A DOE sponsored pilot-scale project has been funded in which 30,000 metric tons of CO2 will be injected in the upper part of the Mississippian reservoir to verify CO2 Enhanced Oil Recovery (EOR) potential at Wellington field in South Kansas. Many conventional Mississippian oilfields in Kansas are going through final stages of water flooding and are at CO2 miscible or near miscible conditions. Wellington Field represents a typical Kansas Mississippian reservoir with very well documented production/injection history and proven performance and, therefore, it is ideal candidate for CO2 EOR. The main objective of this work is to evaluate reservoir properties, predict reservoir response, and evaluate possible risks for CO2 EOR in the Mississippian reservoir at Wellington Field.

Evaluation of Giant New and Mature Oil Fields Developments - History and Prediction Study for Applying Horizontal Wells Using Simulation and Field Practices

Developing giant new and mature oil fields by horizontal drilling is one of the most valuable technologies employed nowadays since it can maximize mature field's benefits. Horizontal wells are offering multiple advantages including, higher production rates, better drainage, lower drawdown and delay water production. In addition, especially in offshore fields, horizontal wells compromise the ability to drill more multi-lateral wells from a single platform enhancing ultimate recovery because of reaching the bypassed oil buckets away from the offshore jackets reducing the number of vertical wells and minimizing offshore infrastructures reducing costs and time. These technologies have been, and will become an attractive topic for more studies and investigations. Development of mature fields, could be included into three major categories (a) well engineering (b) surface facilities and (c) reservoir engineering. This paper focuses on the reservoir engineering aspects and mainly on applying horizontal wells in giant mature fields to maximize their oil recovery. Field maturity in both well engineering and surface facilities will be the subject of next papers. The results have shown that, applying horizontal well drilling in giant mature fields is very crucial because of the horizontal well production improving factor (PIF), which represents the improvement of horizontal well production compared with vertical well production at the same locations, has been significantly increased. Horizontal well production improving factor (PIF) has increased with time along the reservoir life from pre-mature (virgin) to mature phases. In this study, it has increased from 1.23 to 1.28 during the last 9 years (2004-2012). However, simulation prediction results for next 9 years (2013-2021) have shown that, PIF has reached almost 5. That is because the oil column thickness become more thinner due to water movement through moving up toward the water oil contact and through high permeability streaks. As field practice, using pilot holes during drilling new infill and/or re-entry horizontal wells in mature oil fields is essential for successful high potential horizontal wells.

Advanced Wells: A Comprehensive Approach to the Selection Between Passive and Active Inflow-Control Completions

Summary Well architecture advances from conventional wells to horizontal. Then multilateral wells, which have maximized reservoir contact, have been paralleled by advances in completion-equipment development. Passive inflow-control devices (ICDs) and active intervalcontrol valves (ICVs) provide a range of fluid-flow control options that can enhance the reservoir sweep efficiency and increase reserves. ICVs were used originally for controlled, commingled production from multiple reservoirs, while ICDs were developed to counteract the horizontal well's heel/toe effect. The variety of their applications has proliferated since these beginnings. Their application areas now overlap, resulting in it becoming a complex, time-consuming process to select between ICVs or ICDs for a particular well's completion. This publication summarizes the results of a comprehensive, comparative study of the functionality and applicability of the two technologies. It maps out a workflow of the selection process on the basis of the thorough analysis of the ICD and ICV advantages in major reservoir, production, operation, and economic areas. It provides detailed analysis of Reservoir-engineering aspects, such as uncertainty management, formation heterogeneity, and the level of flexibility required by the developmentProduction and completion characteristics, such as tubing size, the number of separately controllable zones, the completion of multiple laterals, and the value of real-time informationOperational and economical aspects, such as proper modeling, gas-and oilfield applications, equipment costs and installation risks, long-term reliability, and technical performance. The results of this work's systematic approach form the basis of a screening tool to identify the most appropriate control technology for a wide range of situations. This selection framework can be applied by both production technologists and reservoir engineers when choosing between passive or active flow control in advanced wells. The value of these guidelines is illustrated by their application to synthetic- and real-field case studies.

Geomechanics Aspects of Multiple Fracturing of Horizontal and Vertical Wells

Summary Although unstimulated horizontal wells have1 been successful in naturally fractured reservoirs and in reservoirs with gas- or water-coning problems, fracturing a horizontal well may be a viable option in certain situations. Because of the dependence of fracture orientation on well direction with respect to the stress field, the possibility of fracturing a horizontal well must be considered before the well is drilled. The appropriate contingency plans should be made to anticipate the possible low production from an unstimulated well. It should be remembered that fracturing a horizontal well may also dictate how the wellbore may be completed or oriented. Fracturing a horizontal well may take place in one of the following situations: Restricted vertical flow caused by low vertical permeability or the presence of shale streaks. Low formation productivity because of low formation permeability. The presence of natural fractures in a direction different from that of induced fractures. Thus, induced fractures have a high chance of intercepting the natural fractures. Low stress contrast between the pay zone and the surrounding layers. In this case, a large fracturing treatment of a vertical well would not be an acceptable option because the fracture would grow in height as well as length. Drilling a horizontal well and creating either several transverse or longitudinal fractures would allow rapid depletion of the reservoir through the fractures. Although fundamentally similar to fracturing vertical wells, fracturing horizontal wells has its unique aspects that require special attention to secure successful treatment. Differences between horizontal and vertical wells exist in areas of rock mechanics, reservoir engineering, and operational aspects. To start with, the basic rock-mechanics aspects are examined.

Genetic Algorithm (GA)-Based Correlations Offer More Reliable Prediction of Minimum Miscibility Pressures (MMP) Between Reservoir Oil and CO2 or Flue Gas

Abstract Two new genetic algorithm (GA)-based correlations were proposed for more reliable prediction of minimum miscibility pressure (MMP) between reservoir oil and CO2 or flue gas. Both correlations are particularly useful when experimental data are lacking and also in developing an optimal laboratory program to estimate MMP. The key input parameters in a GA-based CO2-oil MMP correlation, in order of their impact, were: reservoir temperature, MW of C5+, and volatiles (C1 and N2) to intermediates (C2-C4, H2S and CO2) ratio. This correlation, which has been successfully validated with published experimental data and compared to common correlations in the literature, offered the best match with the lowest error (5.5%) and standard deviation (7.4%). For a GA-based flue gas-oil MMP correlation, the MMP was regarded as a function of the injected gas solvency into the oil which, in turn, is related to the injected gas critical properties. It has also been successfully validated against published experimental data and compared to several correlations in the literature. It yielded the best match with the lowest average error (4.6%) and standard deviation (6.2%). Moreover, unlike other correlations, it can be used more reliably for gases with high N2 (up to 20%) and non-CO2 components (up to 78%), e.g., H2S, N2, SOx, O2 and C1-C4. Introduction The MMP is a vital design parameter for CO2 miscible flooding projects. It impacts both operational and reservoir engineering aspects during the flood. Therefore, an operator must investigate the effects of various factors on the MMP, and consequently, their eventual impact on the project's operational strategy and surface facilities. The main factors affecting MMP are: reservoir temperature, oil composition and injected gas purity. The reservoir temperature has a big impact on MMP, as the MMP increases with the increase in the temperature and decreases with its decrease(1–3). On the other hand, the oil composition has a significant impact on MMP in that the MMP increases with the increase in oil molecular weight. A high oil volatiles fraction (e.g. C1) in the reservoir oil causes the MMP to rise, whereas a high intermediates (e.g. C2-C4) fraction reduces the MMP(2). Furthermore, the presence of non-CO2 (e.g. H2S, N2, SOx and O2) in the injected gas affects MMP, either raising or lowering it depending on the type of the component. From an operational perspective, the existence of these non-CO2 components in the injected gas should not be treated as a rigid impediment. In fact, the existence of certain components such as H2S and SOx could have a positive impact, as they contribute towards lowering the MMP. The presence of C1 and N2, on the other hand, could be detrimental as they cause the MMP to rise. As the separation of such components from the gas is difficult and costly, the current trend is to use the flue gas stream as it is, provided such impurities are below a certain optimum level. A gas stream containing such non-CO2 components are referred to as either low-purity CO2 or flue gas in the context of this paper.

Visual Study of Water Injection in Low Permeable Sandstone

Abstract Visual micro-model technology has been applied to investigate multiphase flow in porous media because it allows watching the fluid flow clearly with a microscope. However, most micromodels employed are made up of glass media. A sandstone micro-model (SMM) manufactured directly from thin sandstone chips is introduced and applied in this study of water injection in low permeable rock. The main advantage for this kind of micromodel is that it retains the original pore structure, clays, cements, and pore surface properties. A total of 18 sandstone micro-models with permeability from 1 - 10 md are used for displacement tests at room temperature. Results show that the water injection in the weakly oil-wet to neutral-wet low permeable sandstone micro-model is dominated by the injection pressure. At low injection pressure, the water can only enter large pores that have good conductivity. A large number of pores are not flooded by water. When the injection pressure is increased, water is forced into some small pores to drive oil out. In addition, heterogeneous properties of the porous media always cause a bypass flow resulting in early water breakthrough and poor water displacement efficiency. We also found that oil recovery is directly proportional to the permeability of the model, suggesting that pore conductivity is the key to waterflood efficiency in low permeable rock. Introduction Glass micro-models (GMM) have been implemented to investigate multiphase flow in porous media at a pore-sized level. The most important advantage employing glass micro-models is its transparent feature that allows the study of multiphase flow in the pore structures with the help of a microscope. Two types of glass micro-models, hypothetical and duplicated, have been used so far. A hypothetical micro-model is produced based on the rock parameters such as throat size, pore body size, and coordinate number. Therefore, such models have a fixed ratio of throat to pore body and the pore structure is very simple. For most cases, the pore structures are repeated. The most popular hypothetical glass micromodel is the network model. The duplicated micro-model is based on a real pore structure that is obtained from a thin section image and reproduced. The pore structure is copied onto a glass plate that is then subjected to an image-etching process using a chemical solution. Compared to the formal model, the latter one has more complicated pore structures. Research applications with visual micro-models include:heavy oil solution gas drive(1–3);gas and water injection and immiscible two-phase flow(4–9); and,enhanced oil recovery(10, 11). Visual micro-model technology has so far provided useful experimental evidence at pore-level and assumes certain hypotheses on aspects of reservoir engineering. However, the application of visual micro-models still has limitations. The most important one is that the glass porous medium is totally different from real rock. Therefore, to restore the initial properties of the selected rock is very difficult. In this work, we present an innovative sandstone micro-model (SMM) which is manufactured from a sandstone chip directly.

New Scale From Non-Darcy Flow Characteristics and Its Use in Aspects of Reservoir Engineering

Abstract This study presents a new concept for the use of non-Darcy flow characteristics in reservoir characterization, development, and well performance. More than 1,000 core samples are analyzed under unsteady-state flow conditions. A universal scale turbulent factor vs. permeability is developed on the basis of the reference base-line of turbulent flow through metallic porous media. This new scale is used to:Classify reservoirs in terms of permeability heterogeneity; and,Establish an iso-turbulence map for reservoir development by selecting adequate zones to drill new wells. In this paper, different applications for Algerian reservoirs are outlined and a new concept for the use of a turbulence factor is highlighted. Introduction This study develops characteristics related to fluid flow through porous media for a turbulent flow regime (high Reynolds number). It involves laboratory experimental analysis followed by numerical and analytical simulations. Six reservoirs are selected: the Upper Trias Shally Sand (TAGS/UTSS) of Hassi R'Mel; the Lower Trias Shally Sand (TAGI/LTSS) of Ourhoud and Rhourd el Khrouf; the Ordovicien of TFT; the Cenomanian Carbonate of Guerguet El Kihal South; and, the Cambrian of both Gassi and Agreb. Data related to these reservoirs include production and core description. The flow of helium under pressure blowdown conditions is performed on 1,600 core samples selected from the above defined reservoirs. In addition, artificial and homogeneous metallic porous media, used for permeameter and porosimeter calibrations, are analyzed in order to establish a base-line for turbulent flow through natural cores. Turbulence factor vs. permeability relationship is developed for each reservoir. A universal scale of these properties is established for improving reservoir characterization in terms of reservoir heterogeneity. Ini tially, analysis is done on the Hassi R'Mel (HR) and Rhourd El Khrouf (RKF) reservoirs(1). The analysis is then extended to additional reservoirs (Sandstone and Carbonates). Layers of the same reservoir are also characterized in order to validate the universal scale. The results show that this developed scale can be considered as a reliable tool for reservoir characterization. The universal scale was also used in the development of the TFT reservoir and to assist with well performance of the Hassi R'Mel field. Literature Review In this section, some ideas that have been developed in the area of non-Darcy flow characteristics are briefly presented. Darcy's pioneering experimental work(2) is well recognized as the key factor in predicting production performance of porous and permeable flow systems. However, in certain circumstances such as the turbulent flow, this law may lead to erroneous results. Forchheimer(3) demonstrated that the pressure gradient to sustain a high flow rate through a porous medium is higher than the one Darcy's equation would predict. As the flow rate increases, the deviation between pressure gradient and flow rate increases. Forchheimer attributed the excess gradient required to inertial flow resistance. As a result, he developed a quadratic form to relate the pressure gradient and fluid flow velocity.

Exploring Reservoir Engineering Aspects of Completion in Gas/Condensate Reservoirs: West African Examples

Summary This paper explores multiple completion options in gas/condensate reservoirs with compositional simulations. Besides intelligent-well completion (IWC), options included commingling two reservoirs of contrasting conductivity (permeability-thickness product) and selectively perforating zones or reservoirs to offset the permeability contrast. At the outset, a value-of-information exercise suggested probing downhole sensing and completion issues in a stacked-reservoir situation. The ultimate objective of this study was to ascertain economic completion strategy so that depletion of reservoirs occurs evenly at the project's termination. Single-well compositional simulations formed the backbone for our evaluation of three completion options. Each reservoir was characterized by history matching drillstem tests (DSTs). Experimental design (ED) reduced the large number of simulation runs to a manageable few for probabilistic forecasting. Comparison of three options suggested that all of them nearly produced the desired results of maximum liquid recovery despite a 10-fold difference in permeability between the two horizons. Results further showed that condensate banking was a nonissue in this high-kh system of reservoirs as far as the gas deliverability is concerned. In other words, although 40 to 60% degradation in the gas productivity index (PI) occurred, gas deliverability remained intact. In contrast, both the liquid PI and rate declined with time owing to phase-behavior and relative permeability issues. Finally, we learned that the net income generated by IWC is no better than the specific-perforation completion (SPC).

Field Foam Applications in Enhanced Oil Recovery Projects: Screening and Design Aspects

Abstract An in-depth analysis covering over forty foam applications in Enhanced Oil Recovery (EOR) projects and numerous production well treatment operations was conducted, to obtain insights on screening and design of such applications. Foam can be used to solve conformance problems caused by either a thief zone or gravity override; proper identification of the cause, as well as of the affected production well(s) is basic to definition of the problem. Either blocking/diverting foams or in-depth mobility control foams can be placed through the injection wells. On the other hand, foam is placed in production wells mainly to mitigate an override problem. The most important factors in foam assisted EOR projects are:manner of foam placement in the reservoir (injection of pre-formed foam, co-injection foam and SAG or surfactant alternating gas foam),reservoir pressure andpermeability. While pre-formed foams are effective in the treatment of production wells, co-injection foam and SAG foam can be employed for solving specific sweep problems. For designing a steam-foam project (which is a low pressure foam application), foam quality in the range 45% to 80% should be considered. In this application, a co-injection foam is employed and the additives (surfactant and non-condensable gas) are injected intermittently (on and off), superimposed on a continuous steam injection. Injection cycles as short as 7 days are common. Under suitable conditions, an oil rate increase of 1.5 to 5 times, a decrease in water cut by 20 %, and an incremental oil recovery of 6%-12% OOIP can be achieved with this implementation. At high pressure, such as in gas miscible flooding, foam application can result in excessive mobility reduction factors, and injectivity reduction. Due to this reason, in these projects, alternate injection of surfactant solution and gas (SAG foam) is favoured over a coinjection mode of placement. Introduction The first review of field applications of EOR foams was published in 19891, and it was not until 1994–1995 that more advanced EOR foam Reviews(2, 3, 4)appeared in the public domain. Building on the previous reviews, more than 40 foam field tests are analyzed here. Unlike the previous reviews, our focus was on the reservoir engineering aspects of foam application, mainly on the mode of foam placement with respect to the problem to be solved. Other differences from the previous reviews include:For the various field tests presented, all available details are tabulated to enable an easy analysis of the data.A reservoir engineering analysis is conducted for the basic recovery process during which foam injection was implemented, in order to establish "a-posteriori", the nature of problem solved.Interpretation of results of field foam applications is based on the results of recent laboratory foam tests on long distance foam propagation In this paper only the key conclusions of our analysis are presented; 19 tables containing the supporting details accompany this paper, and they can be made available by the Journal of Canadian Petroleum Technology, upon request.

Reservoir Compaction

Reservoir Compaction

Reservoir Engineering Aspects of Light-Oil Recovery by Air Injection

Summary This paper addresses the reservoir engineering aspects of air injection as an enhanced oil recovery technique for light-oil reservoirs. In its most successful form, the process has been applied in deep, carbonate reservoirs. The development of this process in conjunction with an application of the in-situ combustion (ISC) process to light-oil reservoirs, as well as the main mechanisms pertaining to ISC and to gas miscible flooding, are analyzed. It is seen that various air-injection processes (AlP's) can be classified, depending on their spontaneous ignition potential and gas miscibility at reservoir conditions, into four different processes. Based on an in-depth literature review, the best reservoir conditions for application of each of these four processes are derived. The main differences in operational aspects (pollution, corrosion, safety) for these processes are also discussed. Design considerations for pilot testing of the technique are presented. The crucial point is location of the pilot on the structure, which is also a key element in its proper evaluation, and its subsequent development to a commercial-size operation. Finally, recommendations on laboratory work in support of design and evaluation of a field pilot are also presented.