Reservoir Appraisal Research Articles

Multifunctional-Team Approach Achieves Extended-Reach Record Offshore Abu Dhabi

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216326, “Longest Extended-Reach-Drilling Well Worldwide Drilled in Middle East, Offshore Abu Dhabi, UAE,” by Marah Mohamad Alabed, Naser Salah Alsuwaidi, and Jamie Scott Duguid, SPE, ADNOC, et al. The paper has not been peer reviewed. _ The complete paper describes the engineering design and operational practices that supported the setting of a new extended-reach world record in a mature carbonate field offshore Abu Dhabi. This accomplishment reduces the carbon footprint of the development, allows acquisition of reservoir data earlier in the development plan, and accelerates production while reducing costs. This extended-reach development program is a strong example of what can be accomplished when a multifunctional team cultivates a strategic plan to expand technical and operational capabilities in a drilling campaign. Reservoir and Development-Plan Background The 1-md oil reservoir is a carbonate dominated by packstone and grainstone rock types in terms of storage capacity. Average porosity is 18%, and thickness is 130 ft. Permeability reduces in an southeast/northwest direction, dropping below 1 md. Calcite cementation development has occurred in the westernmost areas of the reservoir because of late oil in these low structural areas. Initially, the target reservoir was drilled at 2-km well spacing with a five-spot waterflooding scheme from wellhead platform towers. Later, development was optimized by a line waterflooding scheme at 250-m well spacing by development from an environmental island. The target reservoir area was partitioned into four development areas (West A, West B, West C, and West D). The partition is based on drilling reachability from environmental islands and underlying geology. The current optimized development began in the West A reservoir area through an artificially constructed island. The remaining reservoir areas required investment of two new islands. High risk is associated with these investment decisions because these reservoir areas degrade in terms of reservoir rock properties. Additionally, an increasing trend of water saturation exists with progress in the northwest direction within the transition zone. The development plan in the West A area is based on drilling segments called AB and BC, first with over-20,000-ft laterals to achieve production buildup by target date. To test the West B area, Segment BC was extended, thus covering both West A and B areas. This option reduced drilling complexity and maximized the reservoir-production rate. Additionally, by adopting the island drilling option instead of appraising a limited area of West B, an extensive area of approximately 10 km could be appraised. To implement this option, a stepout drilling plan was executed by drilling eight extended-reach maximum-reservoir-contact wells in increments to meet the goal of appraising the West B reservoir area. These first wells were extended in increments of 1,000–2,000 ft to test the capability to drill and run completion to target a measured depth (MD) of 45,000 ft. Upon applying learnings from these pilot wells, a stepout to extending wells to 50,000 ft MD and greater was studied. Fig. 1 shows the map of the subject drilled well with an extended MD of 50,000 ft with an underlying oil-saturation map. This optimized field-development strategy has allowed for effective West B reservoir appraisal.

An Introduction to the Application of Marine Controlled-Source Electromagnetic Methods for Natural Gas Hydrate Exploration

Natural gas hydrates have been an unconventional source of energy since the beginning of this century. Gas-hydrate-filled reservoirs show higher resistivity values compared with water-filled sediments. Their presence can be detected using marine controlled-source electromagnetic methods. We classify acquisition configurations into stationary and moving receiver configurations, which are described in terms of the design group, the operational details, and where they have been used successfully in the field for natural gas hydrate exploration. All configurations showed good numerical results for the detection of a 700 m long gas hydrate reservoir buried 200 m below the seafloor, but only the stationary configurations provided data that can be used to estimate the horizontal boundaries of the resistive part of the reservoir when the burial depth is known from seismic data. We discuss the operational steps of the configurations and provide the steps on how to choose a suitable configuration. Different CSEM configurations were used together with seismic data to estimate the edge of the gas hydrate reservoir and the total volume of the gas hydrates, to optimize the drilling location, to increase production safety, and to improve geological interpretations. It seems that CSEM has become a reliable method to aid in the decision-making process for gas hydrate reservoir appraisal and development.

Joint viscoacoustic waveform inversion with the separated upgoing and downgoing wavefields in zero‐offset vertical seismic profile data

AbstractThe attenuation of seismic waves propagating in reservoirs can be obtained accurately from the data analysis of vertical seismic profile in terms of the quality‐factor Q. The common methods usually use the downgoing wavefields in vertical seismic profile data. However, the downgoing wavefields consist of more than 90% energy of the spectrum of the vertical seismic profile data, making it difficult to estimate the viscoacoustic parameters accurately. Thus, a joint viscoacoustic waveform inversion of velocity and quality‐factor is proposed based on the multi‐objective functions and analysis of the difference between the results inverted from the separated upgoing and downgoing wavefields. A simple separating step is accomplished by the reflectivity method to obtain the individual wavefields in vertical seismic profile data, and then a joint inversion is carried out to make full use of the information of the individual wavefields and improve the convergence of viscoacoustic full‐waveform inversion. The sensitivity analysis of the different wavefields to the velocity and quality‐factor shows that the upgoing and downgoing wavefields contribute differently to the viscoacoustic parameters. A numerical example validates our method can improve the accuracy of viscoacoustic parameters compared with the direct inversion using full wavefield and the separate inversion using upgoing or downgoing wavefield. The application on real field data indicates our method can recover a reliable viscoacoustic model, which helps reservoir appraisal.

Introduction of advanced water management technologies in the Orenburg mining region

The Orenburg Region is rich in various minerals. Dozens of oil and gas fields are being developed on its platform sediment part, while the mountain-folded areas hold deposits of non-ferrous, ferrous and precious metals, rare and radioactive elements, bituminous coal and lignite, and non-metallic minerals. Huge land areas are disturbed by mining, occupied by stock piles of waste rocks and lowgrade ore, and are polluted with spills of oil and deep brines. The economic development of the region is accompanied with an increase in pollution and depletion of water resources. Wide distribution of alkaline land, saline-alkali soils and granitoids containing radon and toxic products of its decay aggravates the impact on the regional hydrosphere. In this regard, it is necessary to study the complex hydrogeology in the region and to evaluate the water quality. The important problems to be solved include: development of the reservoir appraisal methodology; chemical and bacteriological analysis of water and its sensitivity to secondary salinization processes and relics of the marine salt complex; substantiation of water spreading and contamination prevention technologies. The developed recommendations are meant to reach the objective of introduction of modern water management technologies into production as per the resolution of the Russian Government. The article discusses feasibility of water management technologies as a case-study of the Svetly district of the Eastern Orenburg region and the Orenburg urban agglomeration, and necessitates recommendations for their implementation under diverse conditions within the Orenburg Region. As a result of the methodological approach, calculations and modeling of the situation in the mining areas of the Orenburg Region, the effectiveness of the technology of water spreading by means of accumulation of flood water in the local river is proved. The water spreading approach using the active water intakes and conservation reservoirs can increase the productivity of operating wells by 1.5–2 times, enable avoiding depletion of the aquifer and allow meeting the needs of the Orenburg Region’s population in drinking water.

3D Quantitative Characterization of Fractures and Cavities in Digital Outcrop Texture Model Based on Lidar

The combination of lidar and digital photography provides a new technology for creating a high-resolution 3D digital outcrop model. The digital outcrop model can accurately and conveniently depict the surface 3D properties of an outcrop profile, making up for the shortcomings of traditional outcrop research techniques. However, the advent of digital outcrop poses additional challenges to the 3D spatial analysis of virtual outcrop models, particularly in the interpretation of geological characteristics. In this study, the detailed workflow of automated interpretation of geological characteristics of fractures and cavities on a 3D digital outcrop texture model is described. Firstly, advanced automatic image analysis technology is used to detect the 2D contour of the fractures and cavities in the picture. Then, to obtain an accurate representation of the 3D structure of the fractures and cavities on the digital outcrop model, a projection method for converting 2D coordinates to 3D space based on geometric transformations such as affine transformation and linear interpolation is proposed. Quantitative data on the size, shape, and distribution of geological features are calculated using this information. Finally, a novel and comprehensive automated 3D quantitative characterization technique for fractures and cavities on the 3D digital outcrop texture model is developed. The proposed technology has been applied to the 3D mapping and quantitative characterization of fractures and cavities on the outcrop profile for the Dengying Formation (second member), providing a foundation for profile reservoir appraisal in the research region. Furthermore, this approach may be extended to the 3D characterization and analysis of any point, line, and surface objects derived from outcrop photos, hence increasing the application value of the 3D digital outcrop model.

A novel experimental system for accurate gas sorption and its application to various shale rocks

Accurate measurement of shale gas adsorption capacity is crucial for reservoir appraisal and production stimulation. Because of the limited adsorption capacity and finer pore size distribution in shale matrix, it is difficult to precisely quantify the adsorption capacity using traditional volumetric methods for coal adsorption measurement. An improved lab method for shale adsorption measurement and diffusivity evaluation was introduced by using a control group connected through a high accuracy differential pressure transducer. Isotherm curves of five shale samples from different basins were acquired using this system. For all shale samples, adsorption capacity for CO2 is 2–3 times of that for CH4. Adsorption isotherms for shale exhibited a better fitting trend with the BET model at the pressure range of lab scale, indicative of the quick decline at the diffusion-dominant region of reservoir production curve. It is found that the improved adsorption measurement method can effectively reduce the average accumulated error from 24.3%–11.3%, and it is qualified for measurement of materials with limited adsorption capacity.

The influence of reverse-reactivated normal faults on porosity and permeability in sandstones: a case study at Castle Cove, Otway Basin

An understanding of fault zone structure and transmissibility can have significant implications for reservoir appraisal and development within petroleum systems. Studies tend to focus on low porosity host rocks that have experienced simple tectonic histories while the influence of complex fault systems (that have undergone multiple phases of deformation) on porous rocks within fault damage zones have not been investigated. We present results from a detailed mineralogical and geomechanical investigation of the Castle Cove Fault within the Otway Basin at Castle Cove, southeast Australia. Castle Cove provides excellent exposures of the Lower Cretaceous Eumeralla Formation, which is a fine-grained volcanogenic sandstone with moderate to high porosity (up to 27%) and low permeability (mostly <1 mD). The Castle Cove Fault originated as a normal fault during the late Cretaceous and was reverse-reactivated during Miocene–Pliocene compression. Core plugs were sampled at distances between 0.5 to 225 m from the fault and were orientated with respect to the fault plane. We show that closer to the fault (within 75 m), porosity increases by nearly 10% (from approximately 17% to 24%) and permeability increases by two orders of magnitude (from 0.04 mD to 2.92 mD). Microstructural investigations from thin sections show an increase in microfracture intensities closer to the fault. Also observed is a change in the morphology of pore-lining chlorite, from well-structured away from the fault to broken up and disaggregated adjacent to the fault. This study highlights the importance of detailed mineralogical and petrophysical analyses when attempting to understand the reservoir properties of high porosity and low permeability sandstones.

Two-stage and single-stage seismic-petrophysical inversions applied in the Nile Delta

We discuss two Bayesian seismic-petrophysical inversion techniques, the two-stage and single-stage approach, which estimate petrophysical properties from prestack seismic data. Both approaches are developed considering linear approximations and are applied for reservoir appraisal studies in the Nile Delta. The two-stage approach first uses an amplitude-variation-with-angle (AVA) inversion to infer P-wave velocity, S-wave velocity, and density. Then, a linear empirical rock-physics model, properly calibrated for the investigated area, is used to transform the estimated elastic parameters into the petrophysical properties of interest under the assumption of Gaussian mixture distributed petrophysical properties. The single-stage approach uses the linear rock-physics model to rewrite the time-continuous P-wave reflectivity equation as a function of the petrophysical contrasts instead of the elastic constants. This reformulation, together with the assumption of a Gaussian prior model, allows us to directly derive (in a single-stage inversion) the petrophysical properties from AVA data. Despite the differences in the forward-model parameterization and in the assumed a priori distribution for the petrophysical properties, the two inversion methods yield comparable predictions that are consistent with borehole data. For the investigated zone, this work demonstrates that, although neglecting the facies-dependent behavior of petrophysical properties, the a priori Gaussian assumption for the petrophysical properties can provide reliable predictions with a very limited computational effort. In addition, the good match between predicted and logged properties proves the suitability of the linear rock-physics model for reservoir characterization in the Nile Delta.

The permeability structure of fault zones in sedimentary basins: a case study at the Castle Cove Fault, Otway Basin

An understanding of the permeability structure and transmissibility of fault zones can have profound implications for reservoir appraisal and development within petroleum systems. Previous investigations on the permeability structure of fault zones often focus on low-porosity host rocks rather than porous sedimentary rocks which more commonly form reservoirs. We present detailed mineralogical and geomechanical data from porous Cretaceous sandstones (Eumeralla Formation) collected at the Castle Cove Fault in the Otway Basin, south-east Australia. Ten orientated sample blocks were collected in the hanging wall at distances within 0.5–225 m from the fault plane. A progressive increase in porosity (~17–24%), permeability (0.04–2.92 mD), and pore throat size and connectivity was observed as the fault plane was approached. High-resolution thin section analyses revealed an increase in grain-scale fractures and deformation of authigenic clays in sandstones adjacent to the Castle Cove Fault plane. The improvement of the permeability structure of the sandstones is attributed to the formation of grain-scale fractures and the change in clay morphology as a result of faulting. This study demonstrates the importance of detailed mineralogical and geomechanical analyses when attempting to understand the reservoir properties of high porosity, low permeability, and clay-rich sandstones.

Guest Editorial: Keeping Reservoir Stewardship on Course

Guest Editorial The French term, déja vu, which means literally “already seen,” is the feeling that you have previously experienced something you are currently experiencing. Two thirds of adults claim to have sensed this phenomenon, but this figure rises to 100% when one considers professionals in the oil and gas industry, which is undergoing yet another boom-and-bust cycle. Besides the real concern that the recently announced staff layoffs will only hasten the “big crew change” (as some “golden oldies” may decide to call it a day this time around), one hopes that operators will maintain good stewardship of their wells and fields and resist the temptation to cut back on essential data acquisition. Reservoir stewardship, in which operators accept the responsibility to shepherd and safeguard the assets of a company or a country, involves the periodic review of asset performance to ensure productivity and recovery targets are met and maintained, and to guide future work plans. Continuous reservoir appraisal and surveillance are essential to minimize production losses from downtime in wells, facilities, and export systems. Unfortunately, it is evident that some operators (and governments) pay only lip service to good reservoir stewardship, especially when oil and gas prices are low. Sometime ago, I read a student thesis that looked at options for reducing costs in the unconventional “factory drilling” process. It concluded that significant time and money could be saved if formation evaluation services were eliminated from the well program. The project sponsor was happy with the result and the student graduated, but I was appalled that this suggestion could ever be taken seriously. Unconventional reservoirs have complex pore systems, very low interparticle permeability, contain free and adsorbed gas, and exhibit variable water salinity, all of which make their characterization a major challenge for the geoscientist. Therefore, more core data (not less) are needed to calibrate the responses of logging suites, which also require enhanced measurement services as opposed to standard tool strings. The taking of core permits subsequent rock typing to include dynamic properties and fracturability and allows partitioning of the reservoir into zones that reflect quartz content and producibility.

Ten years of marine CSEM for hydrocarbon exploration

Marine controlled-source electromagnetic (CSEM) surveying has been in commercial use for predrill reservoir appraisal and hydrocarbon exploration for [Formula: see text]. Although a recent decrease has occurred in the number of surveys and publications associated with this technique, the method has become firmly established as an important geophysical tool in the offshore environment. This is a consequence of two important aspects associated with the physics of the method: First, it is sensitive to high electrical resistivity, which, although not an unambiguous indicator of hydrocarbons, is an important property of economically viable reservoirs. Second, although the method lacks the resolution of seismic wave propagation, it has a much better intrinsic resolution than potential-field methods such as gravity and magnetic surveying, which until now have been the primary nonseismic data sets used in offshore exploration. Although by many measures marine CSEM is still in its infancy, the reliability and noise floors of the instrument systems have improved significantly over the last decade, and interpretation methodology has progressed from simple anomaly detection to 3D anisotropic inversion of multicomponent data using some of the world’s fastest supercomputers. Research directions presently include tackling the airwave problem in shallow water by applying time-domain methodology, continuous profiling tools, and the use of CSEM for reservoir monitoring during production.

The challenges and impact of compartmentalization in reservoir appraisal and development

Abstract As an industry we have been poor at identifying and predicting the effect of reservoir compartmentalization on fluid flow throughout field life. In the context of harder-to-find reserves and rising development costs it is vital to have a well-rounded strategy in place to identify and mitigate uncertainties and risks associated with compartmentalization. The key challenge of today is therefore to improve predictive capability. Historically we have relied too heavily on ‘single complex’ linear modelling approaches to understand the impact of compartmentalization. Lately, we have begun to place a greater emphasis on using a forensic level of reservoir analysis coupled with the use of dynamic signals from production data and constant down hole monitoring of fluid-type, pressures and temperatures. Evidence is mounting that as fields deplete they evolve mechanically over production time-scales leading to changes in fault behaviour, stress configuration, compaction and hence compartmentalization; such factors are commonly not predicted at start-up. Our challenge has been to develop toolkits and workflows which integrate an appropriate range of geological models iteratively coupled with dynamic data. We need to develop analytical approaches that enable real-time updates from the evolving reservoir &amp; fluid system to iteratively modify our models and improve their predictive power. This will allow us to make better-informed decisions at every stage of field life.

1D viscoelastic waveform inversion for Q structures from the surface seismic and zero-offset VSP data

Wave attenuation is an important physical property of hydrocarbon-bearing sediments that is rarely taken into account in site characterization with seismic data. We present a 1D viscoelastic waveform inversion scheme for determining the quality factor [Formula: see text] from the normal-incidence surface seismic and zero-offset vertical seismic profile (VSP) data simultaneously. The joint inversion problem is solved by the damped least-squares method, and the inversion result is successful using synthetic data. The effects of initial model thickness, [Formula: see text] value, and the existence of noise were studied through a synthetic example. By extracting all of the information contained in the waveforms, the waveform inversion of the seismic reflection and transmission data becomes a powerful tool for estimating [Formula: see text]. For a more comprehensive image of [Formula: see text], the tomographic inversion of [Formula: see text] is applied to the walkaway VSP and prestack surface seismic data, using the waveform inversion result as the initial model. Results from applying the method to a real seismic line and zero-offset VSP data from the Nanyang oilfield, central China, indicate that [Formula: see text] from the tomographic inversion of reflection and transmission data contains useful information on medium properties, which can aid in reservoir appraisal.

Clustering of groundwater chemistry data with implications for reservoir appraisal in West Siberia

Division of sedimentary strata according to groundwater chemistry is discussed with implications for petroleum reservoir potential. It is suggested to process multiparametric water chemistry data from West Siberia using formalized clustering techniques. The efficiency of this approach has been tested for Neocomian clinoform reservoirs with reference to regional-scale appraisal and subregional petroleum division.

Geoquímica de reservatórios

Reservoir Geochemistry has many important practical applications during petroleum exploration, appraisal and development of oil fields. The most important uses are related to providing or disproving connectivity between reservoirs of a particular well or horizon. During exploration, reservoir geochemistry can indicate the direction of oil filling, suggesting the most appropriate places for drilling new wells. During production, studies of variations in composition with time and determination of proportions of commingled production from multiple zones, may also be carried out. The chemical constituents of petroleum in natural reservoirs frequently show measurable compositional variations, laterally and vertically. Due to the physical and chemical nature of petroleum changes with increasing maturity (or contribution of a second source during the filling process), lateral and vertical compositional variations exist in petroleum columns as reservoir filling is complete. Compositional variation can also be introduced by biodegradation or water washing. Once the reservoir is filled, density driven mixing and molecular diffusion tend to eliminate inherited compositional variations in an attempt to establish mechanical and chemical equilibrium in the petroleum column (England, 1990). Based on organic geochemical analysis it is possible to define these compositional variations among reservoirs, and use these data for developing of petroleum fields and for reservoir appraisal. Reservoir geochemistry offers rapid and low cost evaluation tools to aid in understanding development and production problems. Moreover, the applied methodology is relatively simple and gives reliable results, and can be performed routinely in any good geochemical laboratory at a relatively low cost.

Application of microfocus computed tomography in carbonate reservoir characterization: Possibilities and limitations

Normally thin-section petrography, by which observations are made in two dimensions, forms the basis of sedimentpetrological reservoir appraisal studies. In reservoir characterization however, insight in the three-dimensional mineral and porosity distribution is necessary. In this study microfocus computed tomography (μCT), which is a non-destructive technique, has been used for 3D characterization of the mineral phases (i.e. calcite, dolomite, anhydrite) and porosity in carbonate reservoir rocks. In order to obtain quantitative information on density and atomic number of the scanned reservoir samples, as well as about their rock texture, a dual-energy scanning technique has been used. Additional beam artifact correction and a segmentation algorithm, focused on differentiating calcite, dolomite and anhydrite, have been implemented. To validate the developed methodology, thin sections of scanned samples of the Khuff Formation (Oman) have also been analyzed petrographically and compared to corresponding μCT sections and to the results of the dual-energy algorithms. Despite the lower resolution when compared to thin-section analysis, the accuracy of the dual-energy technique is in the range of the standard point counting technique and estimations can be made concerning the microporosity of the samples. Since the developed dual-energy methodology provides a fast and objective determination of the percentages of the mineralogical phases, μCT becomes a very powerful tool in the evaluation of the reservoir potential and in the quantification of mineralogical changes in sedimentary systems (e.g. cycles). In addition, images are acquired visualizing and quantifying the spatial distribution of these phases in three dimensions, which is a major advantage compared to classic 2D thin-section petrography.

Synchrotron FTIR Hydrocarbon Fluid Inclusion Microanalysis Applied to Diagenetic History and Fluid Flow Reconstruction in Reservoir Appraisal

In sandstones, siliceous diagenetic overgrowths may commonly contain several generations of hydrocarbon fluid inclusions (FI's), generally of size no more than 10 µ. We successfully analyzed such inclusions in North sea sandstones from the Dunbar area, subthrusted reservoirs such as sub-Andean basins (Venezuelian and Colombian foothills) and carbonaceous series in areas of Pakistan, using synchrotron infrared microscopy. We addressed, for each case studied, molecular identification and mapping of the components, i.e. hydrocarbon content, and additional molecules such as CO2 , H2 O, in small volumes in their liquid and gas phase as well as the solid phases often associated as products or mechanically entrapped minerals. Semi-quantitative analysis leads to determination of the average composition of each inclusion, i.e equivalent aliphatic chain length (CH2 /CH3 ratios), CO2 and CH4 content. The quantitative method for hydrocarbon chain length measurements was tested first on some exceptionally large FI's (up to 500 µm) previously analyzed by gas chromatography after individual extraction. Homogeneity and /or heterogeneity of trapping as well association of oil with water or their separation is shown for each generation of FI corresponding to a specific organic fluid migration in sandstones from the Brent formation of Dunbar (North sea), and in siliceous reservoirs of subandin basins (Venezuelian and Colombian foothills). Microanalyses of solid phases closely associated within oil in such FI's indicate conditions of the dissolution-recrystallisation processes. Results are particularly promising in carbonaceous reservoirs of Northern Pakistan (Chorgali area, North Potwar basin) where first results pinpoint the effect of TSR mechanism in environments where evaporites were first deposited. PVT modeling of isochores using semi-quantitative SFTIR analyses leads to reconstruction of P-T conditions of diagenesis. Therefore by combining these results with data from organic matter (Genex modeling) and petrography, the onset of cementation was established in the Venezuelian and Colombian Foothills. The path of fluid migration along geological history was then reconstructed with Thrustpack 2D thermal modeling (IFP software), in Tunisian and Pakistani ore deposits and in the carbonaceous reservoir of Chorgali.

Penny-shaped fractures revisited

All methods of seismic characterization of fractured reservoirs are based on effective media theories that relate geometrical and material properties of fractures and surrounding rock to the effective stiffnesses. In exploration seismology, the first-order theory of Hudson is the most popular. It describes the effective model caused by the presence of a single set of thin, aligned vertical fractures in otherwise isotropic rock. This model is known to be transversely isotropic with a horizontal symmetry axis (HTI). Following the theory, one can invert the effective anisotropy for the crack density and type of fluid infill of fractures, the quantities of great importance for reservoir appraisal and management.

Application of Water Injection/Falloff Tests for Reservoir Appraisal: New Analytical Solution Method for Two-Phase Variable Rate Problems

SummaryThe challenges of reducing or eliminating emissions associated with well-testing operations during reservoir appraisal have revived interest in water injection/falloff tests. However, the two-phase flow and injection-induced temperature changes associated with injection/falloff tests complicate the problem of well-test analysis. Strictly speaking, these effects make the pressure transient problem nonlinear and preclude using conventional superposition technique to construct solutions for variable rate problems.In this paper, we present a new analytical method for accurate solution of the pressure transient problem for two-phase flow associated with water injection/falloff tests. The solution algorithm allows one to compute the solution for any stepwise constant rate sequence that includes multiple injection and falloff periods. The method is general, and can be used for water injection governed by any physically meaningful relative permeabilities, as well as for pistonlike displacement.

Electrical Measurements in the 100 Hz to 10 GHz Frequency Range for Efficient Rock Wettability Determination

Summary This paper summarizes an experimental and theoretical study conducted to investigate the effect of rock wettability on the electrical response of water- and oil-saturated core samples in a wide frequency band. The aim of the study was to evaluate a technique not previously applied to wettability determination as a practical alternative to conventional tests, and to ascertain the consequent economic and technical benefits in reservoir appraisal.