Shaly Reservoirs Research Articles

Shale distribution effects on the joint elastic–electrical properties in reservoir sandstone

AbstractWe investigated the effect of shale distribution on the joint elastic wave and electrical properties of shaly reservoir sandstones using a dataset of laboratory measurements on 75 brine‐saturated (35 g/L salinity) rock samples (63 samples from the literature, 12 newly measured samples). All the data were collected using the ultrasonic (700 kHz) pulse‐echo measurement technique for P‐ and S‐wave velocities (Vp, Vs), attenuations (Qp−1, Qs−1), and a four‐electrode method for resistivity under elevated hydrostatic confining pressures between 10 and 50 MPa (pore fluid pressure 5 MPa). The distribution of volumetric shale content was classified by comparing the calculated dry P‐wave modulus to the modified Upper Hashin–Shtrikman bound for quartz and air mixtures, assuming pore‐filling shale. This scheme in particular allowed us to distinguish between pore‐filling and load‐bearing shale distributions according to idealized definitions, which provides new insight into the joint ultrasonic properties and resistivity behaviour for shaly sandstones. In resistivity–velocity space, the resistivity of load‐bearing shale increases with increasing velocity which form a more distinct trend with steeper gradient compared to those for partial pore‐filling shale and clean sandstones. Moreover, the pore‐filling shale trend straddles the clean sandstone trend and meets the load‐bearing shale trend between 100 and 150 apparent formation factors. In resistivity–attenuation space, the highest attenuations exist when the volumetric shale content is close to the frame porosity (for Qp−1 in particular), at the transition between pore‐filling and load‐bearing shales. The results will inform the development of improved rock physics models to aid reservoir characterization from geophysical remote sensing, particularly for joint seismic and controlled source electromagnetic surveys.

A new integrated approach to resolve the saturation profile using high-resolution facies in heterogenous reservoirs

The saturation calculation in complex reservoirs remains a major challenge to the oil and gas industry. In simple formations, a tendency towards simple saturation models such as Archie or Simandoux for clean and shaly reservoirs respectively is always preferable. These models were found to be working effectively in homogeneous formations within which the porosity and permeability are linked in the light of a simple facies scheme. Where the rocks show some degrees of heterogeneity, the well-logs are usually affected by different factors. This adversely results in a compromised or averaged log profiles that may affect the saturation calculations. Four wells drilled across a shaly sand of high heterogeneity have been studied in the Perth Basin, Western Australia. The aim is to resolve the hydrocarbon saturation and explain the high productivity results, despite the high water saturation, obtained through a conducted formation well test across the interested reservoir zones. A new integration technique between a suite of conventional and advanced logging tools together with the capillary pressure measurements has been carried out to generate a high-resolution reservoir saturation profile, that is lithofacies dependent. Three different independent methods were used in the studied wells to calculate the saturation and to reduce the uncertainty of the final estimated profiles. The methods are the resistivity-based saturation, the NMR-based irreducible saturation, and a new application through saturation height modeling. Furthermore, through the workflow, an effective calibration for the magnetic resonance T2 cutoff has been applied that is supported by the excellent reservoir production behavior from such complex reservoir. The methodology will help resolve the saturation calculation as one of the most challenging reservoir parameters, particularly where the resistivity logs are affected in complicated shaly sand environments. The effectiveness of the workflow shines the possibility to predict high resolution facies and saturation profiles in the lack of resistivity logs. A further possibility can complete the analysis on real time basis, which can certainly provide facies and saturation profiles extended to the uncored wells. Application of this methodology in the uncored wells has shown very encouraging results in various well trajectories, either vertical, deviated or horizontal long boreholes.

A novel method to improve water saturation in shaly sand reservoirs using wireline logs

Water saturation in shaly reservoirs is a difficult task due to the heterogeneity nature of shale and the way the shale distributed in the reservoirs. So, many scientists proposed several models for water saturation in shaly sandstone reservoirs. So far, the most reliable techniques depend on identification of shale habitat qualitatively to apply suitable water saturation model, these techniques can lead to inaccurate identification of shale habitat, especially when dealing with a mixture of different shale modes and massive superimpose well logging data, and hence drastically erroneous values of water saturation and hydrocarbon reserves. Well logs and routine core analysis from two main fields in Egypt. The North Sinai and the Gulf of Suez fields are used for this study to evaluate the novel proposed method. Unlike other qualitative methods, a new robust method has been introduced to determine accurate volumes of shale distribution types. This volumetric method checked for validation and accuracy using Thomas-Stieber crossplot, the results show good and a reliable degree of accuracy. Consequently, appropriate water saturation models can apply accurately. While the dispersed shale model is adequate to estimate water saturation in dispersed shale reservoirs, water saturations for laminated shaly sand reservoirs are more complicated. So, a new approach and algorithms have been introduced to evaluate water saturation in these complex problematic reservoirs specifically in the absence of triaxial induction resistivity measurements. Furthermore, to prove the superiority of this novel method over traditional techniques, a comparative study and statistical analysis performed between the new water saturation method and conventional techniques by using InetillLog software © 2015. These comparisons and statistics show a remarkable discrepancy and variance in values between conventional methods and the new method, where water saturation values obtained from conventional methods for two fields are drastically lower than the new method. This can lead to erroneous water saturation and hydrocarbon estimations. Water saturations derived from the new method were in perfect agreement with the corresponding water saturations from cores data. Moreover, scatter diagrams between water saturation from novel method and that from core analysis obtained correlation coefficient (R2) values of 0.82, 0.85, for the North Sinai and the Gulf of Suez fields, respectively, indicating strong linear relationships. Furthermore, this new method is taken care of one of several pitfalls of LSSA interpretation method. So, this novel method adds a valuable improvement in water saturation, the assessment of hydrocarbon saturation in shaly reservoirs, continuous Net To Gross (NTG) calculations, net pay detection, reservoir simulation, and reserve estimation.

Evaluation of Nubia sandstone reservoir as inferred from well logging data interpretation for Rabeh East-25 well, Southwest Gulf of suez, Egypt

The present study interprets well log responses obtained from the Nubia sandstone in the Rabeh East-25 Well, Southwest Gulf of Suez in Egypt. The reservoir characterization of the Nubia sandstone reservoir demonstrates that it has excellent potential for hydrocarbon production. Based on the qualitative interpretation of available well log data, the examined well through the Nubia sandstone succession has been subdivided into four zones. The hydrocarbon-bearing zones include zone II, a shaly reservoir occurs between depths of 5610 and 5631 ft, and zone IV, characterized by a clean sandstone reservoir is located between depths of 5656 and 5685 ft. When both zones are combined, the net pay thickness of the Nubia sandstone reservoir in the studied well reaches 60 ft. The petrophysical parameters of the oil-bearing zones were calculated to determine their reservoir properties, including their fluid saturation, shale volume, porosity, bulk volume of water and permeability values. The shaly sandstones in zone II have low water saturation (17–47%), low shale volume (0–50%), high total porosity (18–23%) and high effective porosity (8–23%) values. However, the clean sandstones in zone IV display lower water saturation (8–38%), high total porosity (17–22%) and high effective porosity (14–22%) values. Both zones exhibit high permeability values (usually above 50 MD), and their values of the Movable Oil Index are lower than 0.7reflecting the movability of the preserved oil. The constructed Buckles plots for the two zones indicate that the points which follow 0.04 and 0.05 BVW hyperbolas in zone II and points track 0.02, 0.03 and 0.035 BVW hyperbolas in zone IV will produce oil without water. The relative permeability to oil is usually less than 1.0, and the relative permeability to water is less than 0.01. Additionally, the water contents accompanying production are relatively low, i.e., they vary between 0 and 20%, thus reflecting the good reservoir quality of both zones.

Numerical simulation of the impact of geological heterogeneity on performance and safety of THAI heavy oil production process

The Toe-to-Heel Air Injection (THAI) in-situ combustion process is an efficient way to extract heavy oil and bitumen. However, such reservoirs are often geologically heterogeneous. This work studied the impact of a range of different geological heterogeneities, often found in bitumen deposits, on the performance and safety of THAI. These heterogeneities included random heterogeneity, layered reservoirs, shaly reservoirs, and semi-permeable cap-rocks. A further aim was to also develop potential remedial measures, such as selective well placement. It was found that the degree of symmetry assumed for the reservoir model had a substantial impact on the predicted level of oil production. This is of particular relevance to otherwise apparently symmetrical well placement designs such as staggered line drive. While the presence of impermeable zones resulted in the decrease in the overall oxygen utilisation for shaly reservoirs, compared to simply low permeability reservoirs, there was no evidence of oxygen breakthrough due to preferential channelling into the production well. In layered reservoirs, the development of a rich oil bank during THAI operation depended upon the distribution of permeability around the horizontal producer (HP), and did not occur when there was high permeability just above the HP. It has been shown that the proper representation of the cap-rock in reservoir models for the simulation of THAI is essential in order to accurately mimic the full pattern of heat distribution into the oil zone of the reservoir, and, thence, fuel lay-down. While THAI can operate stably with a permeable cap-rock, vertical permeabilities above ∼1–3 mD led to significant loss of combustion gases from the reservoir.

English

Shaly sandstone reservoirs have complex pore systems with ultra-low to low interparticle permeability and low to moderate porosity. This has led to development of several models to calculate water saturation in shaly sandstone reservoirs using different approaches, assumptions and certain range of conditions for application. This study has used actual well logging data from two different fields of South Texas and North Sea to evaluate and compare the most popular five shaly sandstone models for calculating water saturation. Furthermore, sensitivity analysis of tortuosity coefficient (a), cementation exponent (m) and water saturation exponent (n) is achieved to investigate their effects on computed values of water saturations using different models. The results indicated that the increase of shale volume decreases water saturation calculated for all popular models. In addition, the increase of tortuosity coefficient and/or cementation exponent (m) causes overestimation of water saturation while the increase of saturation exponent (n) results in underestimation values. The results also showed that the increase of shale volume decreases water saturation calculated for all popular models. In addition, the increase of tortuosity coefficient and/or cementation exponent (m) causes overestimation of water saturation while the increase of saturation exponent (n) results in underestimation values.   Key words: Shaly reservoirs, water saturation, well logging, field analysis.

A new technique for identification of flow units of shaly sandstone reservoirs

The available techniques for identification of flow units of shaly sandstone reservoirs are based on different concepts, do not provide satisfactory results, and usually show discrepancy. This research is devoted to evaluating current techniques and developing a new concept capable to identify flow units constituting shaly sandstone reservoirs. A new mathematical model has been developed and validated to identify flow units in shaly sandstone reservoirs. The newly developed concept is called shale number (SN) and combines rock properties, fluid properties, petrophysical properties, and hydraulic flow conditions of shaly reservoir rocks. Fifteen actual, reserved, and fracture-free reservoir samples of shaly sandstone reservoir are used to develop SEM images and measure required rock properties of porosity, permeability, and oil/brine relative permeability. The developed data using SEM images and lab experiments are used to characterize the rocks, test feasibility of permeability-porosity crossplot and flow zone index (FZI) techniques, and validate the newly developed mathematical model. The results revealed that the SEM images are capable to identify the clay types as detrital clays and hairy illites plus clay distribution as filling micropores and coating grains of shaly sandstone formations. The results have proven that techniques of porosity–permeability crossplot and FZI have severe scattering degree of data and poor capability for identification of flow units of shaly sandstone reservoirs. The developed model of SN has been validated and showed superior accuracy in application. A plot of SN versus reservoir quality left( {sqrt {K/varphi } } right) provided unique straight lines passing through the origin and capable to delineate flow units of shaly sandstone reservoirs. The newly developed shale number overcomes several drawbacks of previous and current techniques used for identification of flow units. Therefore, the application of the new technique provides improved reservoir description of shaly sandstone reservoirs, which secures better development planning.

Lithology Investigation of Shaly Sand Reservoir by using Wire Line Data, “Nubian Sandstone” SE Sirt Basin

Identify the rock lithology has important meaning for estimating the reserve of petroleum as reservoir capacity and storage ability. The lithology identification from well log based on not conventional cross plot proposed and studied, which is more easier instead of rock core data observation results. However, this work carried out comparison between chart and analytical solution of matrix parameter (ρma and ΔTma) estimation values of producer shaly sand reservoir, and present the main depositional environment affects. In addition to influences of pyrite, ferruginous encrustations, organic material throughout this studied reservoir. Consequently, variety of matrix parameters values is contributed by clay minerals present in this reservoir type. This study based on wire line data measured over than 750 feet produced Upper Nubian Sandstone belong to two oil fields, SE Sirt Basin. This shaly reservoir divided into three main units (R, E and F), and each unit has been subdivided into three subunits (F3, F2, F1, E3, E2, E1, R3, R2 and R1) from bottom to top according to depositional and petrophysical properties.

Research on saturation computation model and parameter determination methods for low permeability reservoirs with high mud

Gulong oilfield lies in the intersection of provenance of western peripheral Song liao Basin, where the reservoir permeability is low and the mud and calcic is high, resulting in the complicated calculation in water saturation. The common saturation computation model for shaly reservoirs can not get a better application in the field scale development due to more parameters .Based on the classic Archie formula, the formula of water saturation for the shale and calcareous reservoirs is derived to fit for field scale development,and the obtaining value methods of change value which is related to formation depth and porosity are respectively established guided by geochemical field theory and classification statistics at the same time aiming at two difficulties, which are the value of formation water resistivity in the Archie formula is difficult to obtain and the rock-electro parameters are greatly affected by pore structure. The relative error of the result of the established model is 5.38% compared with the actual sealing core data, and the effect is good. It is shown that the model and the parameter value decision methods have guiding significance in scale development for low permeability reservoirs with high mud and calcic content.

Monitoring the Effect of Discontinuous Shales on the Surfactant Flooding Performance in Heavy Oil Reservoirs Using 2D Glass Micromodels

Although most heavy oil reservoirs contain discontinuous shaly structures, there is a lack of fundamental understanding how the shaly structures affect the oil recovery efficiency, especially during surfactant flooding to heavy oils. Here, an experimental study was conducted to examine the effect of discontinuous shales on performance of surfactant flooding by introducing heterogeneities to represent streaks of shale in five-spot glass micromodels. Results show that oil recovery in presence of shale streak is lower than in its absence. Based on the authors’ observations, the presence of flow barriers causes premature breakthrough of injected fluids and also an unstable displacement front. As well, displacement efficiency of surfactant flooding is dependent strongly on the shale distribution configuration. Increasing shale content causes reduction of ultimate oil recovery and also severe fingering during water flooding while it compensates during surfactant flooding considerably. In shaly patterns, in the case of surfactant flooding, the oil recovery after breakthrough increases significantly, while it changes much less for the case of water flooding as well as flooding in homogeneous model. Oil recovery efficiency and breakthrough time improved with increasing surfactant concentration. However, beyond a specific limit of sodium dodecyl sulfate concentration, around 2000 ppm, incremental oil recovery becomes insignificant. Presence of connate water in surfactant flooding scheme can improve the recovery efficiency in shaly patterns. Results of this work can be helpful to investigate the optimal location of injection/production wells during enhanced oil recovery schemes in shaly reservoirs using five-spot micromodels.

Performance of Polymer Flooding in Anisotropic Reservoirs with Discontinuous Streaks of Shale

Many oil reservoirs contain discontinuous shale streaks, which may affect the flow behavior as well as oil recovery efficiency. To investigate and compare the performances of polymer flood processes in anisotropic shaly reservoirs, an extensive numerical simulation was performed for polymer flood followed by waterflood. A series of polymer and water injection simulations have been carried out at various conditions in the length, direction, and spacing of shale streaks and level of reservoir anisotropy. Reservoir performances were compared in terms of cumulative recovery and water-oil ratio at the production well and injectivity at the injection well. Results from the study have demonstrated that oil recovery can be significantly affected by shale streaks with increased length and shorter space. It was observed that the shale streaks cause bypassing of displacing fluids due to disruption of main flow path and, consequently, lower injectivity. Increasing shale content causes the degree of fingering to be increased significantly during polymer flooding. The effects of heterogeneity introduced by streaks of shale were maximized when the direction of displacing fluid flow was perpendicular to the direction of shale streaks and parallel to higher permeability in the anisotropic reservoir models. Results of this work can be helpful for successful design and accurate prediction of EOR processes based on shale distribution in anisotropic reservoirs.

Reservoir Subdivision and Prediction of Poisson's Ratio According to Wireline Data (Hawaz Reservoir, Libya): Case Study

Critical property that affects wellbore stability, perforation depths and hydraulic fracturing is Poisson’s Ratio (PR). Porosity and resistivity are the main petrophysic properties routinely are measured for any reservoir rock. In this approach utilize wireline data (GR, R, On and ρb) to classify shaly reservoir and predicate PR values. Therefore, range of shale content (over 20%) has PR over 0.2. while shale content (less than 20%) equivalent to PR equal to 0.18. According to variety of shale content percentage throw up change of PR values. This technique applied on one of major shaly sand reservoir rock, producer in Libyan oil fields, Hawaz at Murzuq basin, south-west of Libya; as a case study.

Vertical Permeability From In Situ Horizontal Measurements in Shaly-Sand Reservoirs

Abstract The oil industry has become increasingly aware that reservoirs exhibit complex variations of reservoir continuity; in particular, of pore space-related properties such as porosity, permeability, and capillary pressure. These variations reflect the original depositional process, and subsequent diagenetic and tectonic changes. Simple models are often inadequate for predicting reservoir performance and designing a field production management program that optimizes recovery. It is evident to reservoir engineers that optimization depends on the quality of the reservoir undergoing water injection, where the recovery factor is very sensitive to reservoir heterogeneity. Therefore, an accurate knowledge of vertical and lateral permeability distribution is essential. This paper represents results of a research project aimed at determining vertical permeability from in situ horizontal permeability in shaly reservoirs. This is accomplished by considering the microscopic and macroscopic features, such as the type of shale (Kaolinite, Chlorite, and Illite) and grain size. In situ vertical permeability correlations are derived by using various water saturation correlations for Shaly-Sand formations. Several vertical permeability relationships were obtained as a function of horizontal permeability, hydraulic mean radius grain size, and the amount and/or type of shale. Generalized models were developed, and were applied to real oilfield data for calculating vertical and horizontal permeabilities. Introduction Permeability is one of the most important of all formation parameters used by petroleum engineers to determine whether a well should be completed and brought online or abandoned. Vertical permeability is also essential in developing a reservoir management and development program, including determining the optimal drainage points and production rate, optimization completion and perforation design, and planning EOR patterns and injection conditions. Extensive research on permeability has been conducted on clean formations for decades. Vertical permeability in Shaly-Sand formations has long been viewed as problematic. Formations with shale and/or different pore geometries constitute the majority of heterogeneous reservoirs. In this case, reservoir heterogeneity is no longer viewed as a problem, but rather as an opportunity for recovering more oil. In early studies of reservoir engineering, reservoirs were assumed to be homogeneous and isotropic, but also non-uniform. In recent studies, however, the porosity-permeability transform has been used for a better description of a reservoir having some complex geological continuity. Clark(1) showed that, if the rock grains are large, flat, and uniformly oriented along the longest dimension, then the horizontal permeability (Kh) would be higher than the vertical one. Clark(1) also showed that, if the rock was composed mostly of large and uniformly rounded grains, its permeability would be considerably higher and almost equal in both the horizontal and vertical directions. Generally, vertical permeability is lower than horizontal permeability, especially if the sand grains are small and have irregular shape. Most petroleum reservoirs fall in this category. Neasham(2) studied the effect of clay on permeability. He showed that the morphology of clay with the highest air permeability is predominantly the discrete particle. The morphology of dispersed clay in samples falling within an intermediate air permeability range is predominantly of a pore-lining variety.

A New Approach for Obtaining J-Function in Clean and Shaly Reservoir Using In Situ Measurements

Abstract Leverett's capillary J-function has been widely used in the petroleum industry as an effective tool for correlating capillary pressure data with rock properties. The major goals of this study are: (1) to investigate the effect of stress on the calculated values of J-function, and (2) to develop new models capable of obtaining the J-function using in situ measurements in clean and shaly heterogeneous reservoirs. Two models are developed, in which well-logging data, a good source of in situ measurements, are used to calculate the Jfunction. The first model was obtained using Tixier's permeability equation and Archie's equation for water saturation. The second model was derived using Tixier's permeability equation in combination with the Schlumberger shale model for water saturation determination. These models were validated using actual field data from two reservoirs in Oklahoma and Louisiana. Introduction Leverett's capillary pressure J-function has been widely used in the petroleum industry as an effective tool for correlating capillary pressure data with rock properties. Capillary pressure data is a very useful tool, since it reflects the pore size distribution, the radius of the largest pore, the rock wettability, and the interfacial tension of fluids in the system. Leverett(1) developed the basic theory for the behaviour of the flow of fluid mixtures in reservoir rocks. He used well established thermodynamic and physical principles in the development of his theory. He divided the problems into two groups:Static problems, involving only the static balance between capillary forces and those due to the difference in densities of the fluids (gravitational forces), andDynamic problems, involving analysis of the flow of immiscible fluids in porous media under the effect of gravity, capillary, and external differential pressure forces. The J-function is a very useful tool for correlating capillary pressure data and rock properties. Hence, it is an effective tool for the better description of reservoir rock and the behaviour of the capillary retention of the wetting fluid. The Concept of J-Function Leverett conducted several experiments using unconsolidated clean and clayey sands for the development of a dimensionless group called the "Leverett J-function." He used the J-function to correlate capillary pressure (PC), interfacial tension (σ), in addition to permeability (K) and porosity (φ) of the porous rock. He found, from the results of his experiments, that a dimensionless group of the form [PC / σ* √ (K/ φ)] vs. water saturation (SW) gives two satisfactory but closed curves, one for imbibition of water and the other for drainage. Leverett's data showed that a plot of this dimensionless group vs. the wetting-phase saturation (SW) yielded a unique curve describing the capillary retention of the wetting liquid existing in the clean, unconsolidated sands, when capillary forces were at equilibrium, as shown in Figure 1. Later, Leverett et al.(2) proved theoretically, using the dimensionless analysis technique, that capillary pressure is proportional to the interfacial tension, to the radical v(K/ φ), and to the dimensionless function of the water saturation J(SW).

Influence of Stress on the Characteristics of Flow Units in Shaly Formations

Abstract Reservoir evaluation of shaly formations and enhancement of reservoir characterization has long been a difficult task. This study is devoted to developing relationships for interpreting the combined effects of subsurface stress and shale on petrophysical properties of reservoir rocks. These new relationships are used to: (1) identify shale types, (2) characterize flow units in shaly formations using in situ measurements, and (3) study the effect of stress on reservoir quality index and fluid flow paths of shaly formations. Several flow unit models have been developed to achieve these goals. The proposed flow unit models are based on current shale models appearing in the literature. These flow unit models introduce unique parameters for reservoir characterization of shaly formations. These parameters include the slope of a traight line (that defines the flow unit) and the stress factor on a log-log plot of in situ reservoir quality index versus in situ porosity of the shaly formations. Finally, these models are used to identify shale types and select a suitable water saturation model for shaly formations. The models are validated using simulated data of porosity and pressure. The new models, in combination with the methodologies developed in this study, represent an effective tool for an enhanced reservoir description of shaly reservoirs. Introduction Characterization of shaly formations has been a difficult task for several reasons. One key factor of this difficulty is that the use of conventional core test data simply does not work. Special equipment or procedures are required to determine the low permeabilities and porosities. A serious, and more fundamental, problem related to studying shaly formations is that of the very heterogeneous nature of shales. In addition, the consideration of the subsurface stress effect will make investigation and characterization of shaly formations much more difficult. With respect to the stress effect, Hilchie(1) used six brine saturated porous samples under simulated conditions of overburden and temperature. The simulated overburden pressure used was up to 68.45 mPa (10,000 psi) and the simulated temperature conditions were up to 232 °CDATA[C (450 °CDATA[F). The results showed that the increase of stress caused an increase of the formation resistivity factor. Longeron(2) investigated the effect of overburden pressure on the electrical properties of sandstone. The results showed that the formation resistivity factor increased by about 15﹪ for sandstone when stress ranging from 276 mPa to 20 mPa (400 psi to 2,900 psi) was applied. Lewis et al.(3) investigated the effects of stress and wettability on the water saturation exponent "n" and the cementation exponent "m." The results showed that changes in stress have a relatively minor effect upon the water saturation exponent "n" and the cementation exponent "m," but trends having an increase in these exponents with increasing stress levels have been observed. Lewis et al. data also showed a slight decrease in these exponents with decreasing stress, but the effectf stress on the water saturation exponent "n"was less clear than that of the cementation exponent "m."Therefore, changes in the cementation and water saturation exponents are probably small enough that they can be neglected.

Abstract: Using an Outcrop Analog of a Shaly Reservoir to Evaluate the Impact of Fault-Related Fracturing on Oil Production 

Abstract: Using an Outcrop Analog of a Shaly Reservoir to Evaluate the Impact of Fault-Related Fracturing on Oil Production 

Water Saturations in a Wilcox Shaly Reservoir Sandstone, Fordoche Field, Point Coupee Parish, Louisiana: ABSTRACT

ABSTRACT A new model has been derived for calculation of water saturation in shaly reservoir sandstones. The model is based on effective medium theory (EMT) and has been used successfully on a wide range of clayey, low-resistivity reservoirs. A further, independent test of saturations calculated by the model was made for a deep Wilcox shaly reservoir at a depth of 13,176 ft (4016 m) in Fordoche field. The reservoir (W8) has a low, average resistivity of about 2.5 ohm-m and an estimated 18% clay as compared to an average resistivity of 1.5 ohm-m in an underlying wet sandstone (W-10) of similar clay content. For the reservoir, calculated water saturations are in the range of 35 to 50%, increasing downward, and suggest that the shaly sandstone should produce water-free oil. Other shaly sand models generally give water saturations in excess of 50% for the reservoir. Water saturations calculated by the EMT model agree well with other parameters for sandstones: reported production, core analysis, and synthetic capillary pressures. The reservoir (W8) had an initial potential of 213 bbl of oil per day, confirming water-free oil production which could have been predicted by the EMT model.

Log-Derived Evaluation of Shaly Clastic Reservoirs

Summary. Reliable evaluation of hydrocarbon resources in shaly clastic reservoir rocks is an important, although difficult, task. This paper briefly reviews the wide variety of interpretive models that has evolved. The discussion focuses on digital shaly-sand evaluation techniques based on the Waxman-Smits model to provide information on total and effective reservoir porosity and fluid distribution, silt content, volume, type (smectite, illite, and chlorite/kaolinite), and distribution modes (dispersed, laminated. and structural) of the clay minerals present in subsurface formations. Case studies from different geologic environments present field experiences in clastic reservoir rocks that exhibit a wide range of porosity and permeability and various amounts, types, and distribution modes of clay minerals. A log-derived formation damage index is also discussed. Finally, emphasis is placed on improved reservoir evaluation of thinly laminated shale/sand intervals through the integration and enhancement of resistivity data, short-spaced dielectric measurements, and/or analytical data-blocking routines. Introduction Few hydrocarbon-bearing clastic reservoirs are essentially free of clay minerals. The significant effect of these minerals on geophysical log responses is well recognized. Ref. 1 represents the first modern collection and comprehensive review of the vast number of technical papers important to the evaluation of shaly clastic reservoir rocks based on geophysical well logging measurements and associated interpretive concepts. For example, Fig. 1 illustrates the generalized response of the various porosity logs to shaliness and hydrocarbon effects. The basic objective in shaly-sand formation evaluation then is a realistic log-derived description of reservoir quality in terms of petrophysical parameters, type, and volume of hydrocarbon resources in place, and expected production behavior. Such evaluation methods may be simple empirical rules, standard analysis concepts, digital wellsite "quick look" techniques, or advanced digital interpretive models used in single-well or multiwell field studies. Basic Considerations In his classic empirical equation, Archie related formation conductivity, formation-water conductivity, and the formation resistivity factor (a function of porosity and cementation exponent) to the formation-water saturation. Archie's equation applies satisfactorily to clean sands, whereas the presence of clay minerals (amount, type, and distribution modes) has a detrimental effect on water saturation calculations. While more than 30 water saturation models have been proposed for shaly-sand reservoir evaluation, most of the major developments can be classified in one of four categories (see Table 1 ). Worthington recently discussed these categories and the evolution of shaly-sand concepts in reservoir evaluation. Concepts based on clay volume, V, exhibit two constraints: being inexact and requiring reliable log-derived V, estimates. 3 The latter, in itself, is no minor task (see Table 2). The most common clay minerals, their chemical composition, matrix density, hydrogen index (HI), cation exchange capacity (CEC), and distribution of potassium, thorium, and uranium as shown by natural gamma ray spectral information are summarized in Table 3. Because a typical shaly clastic reservoir rock and/or a typical shale formation may contain different clay minerals in various amounts, no single clay parameter can be used universally to characterize a specific type of argillaceous sediment or shaly reservoir rock. With the advent of the Waxman-Smits model, reliable water saturation calculations are provided for reservoirs with drastically different clay contents and over a wide range of formation-water salinities. The emphasis is on log-derived evaluation of CEC per total PV, Qv, from specific single or combined well logging parameters. Such QV, estimates from well logs can be based on the spontaneous potential curve, gamma ray, natural gamma ray spectral data (potassium, thorium, and uranium), dielectric measurements, reservoir porosity, gamma ray/reservoir porosity, clay composition/reservoir porosity, etc. It suffices here to state that such correlations faciliLate a continuous computation of CEC and Q v values for a given formation in a geological section or localized area. These techniques, however, all require both well logging and core data over the interval of interest because no single unique mathematical transform can be expected. To overcome these limitations, advanced digital shalysand analysis techniques, such as CLASS and CLAYS, have recently been developed. Based on the WaxmanSmits model and variations in the basic properties of various clay minerals, CLASS and CLAYS analyses provide information on total and effective porosity; total and effective fluid distribution silt volume; amounts, types, and distribution modes of clay minerals present, and reservoir productivity. Details of these methods can be found in Refs. 6 and 7. JPT P. 175^

Evaluation of Shaly Sands With Low Deliverability

Abstract Historically, wells encountering only shaly sands with low deliverabilities have been abandoned as dry holes, and exploration for such reservoirs has been considered uneconomical. With an increasing demand for hydrocarbons, however, shaly reservoirs such as the Second White Specks, Milk River, Medicine Hat and Belly River of southern Alberta and Saskatchewan, formerly considered uneconomical plays, have now become sought-after prospects. Evaluation of these very shaly reservoirs has proved to be neither simple not straightforward. Systems normally used for exploration and evaluation (logs, cores, drill-stem tests) were designed for clean sands with high deliverabilities. All these system have been hampered by the shale content of the sands. Recently developed methods of log analysis can define and adjust for shaliness effects. After adjustment for shaliness, the logs are capable of supplying such information on the reservoir thickness, hydrocarbon content, hydrocarbon type and identification of producible zones. Available logging programs and their interpretation, including an adjustment for shaliness, are discussed in this paper. The manner of interpreting logs, in the above shaly formations is developed in the discussion of the field examples, and the results of log interpretation are compared to the results of Core analysis and production tests. Introduction THE Second White Specks, Medicine Hat, Milk River and Belly River sand formations have several common characteristics. They extend from southwestern Saskatchewan through the Alberta plains as shalysand reservoirs with proven productivity. Generally their deliverability is low - less than 1 MMcf/D or 50 BOPD. Evaluation of these shaly sands is complicated by large variations in shale content, variable lithologies and low permeabilities. Current logging equipment and recently developed log interpretation techniques are capable of providing rapid, reliable evaluation of these zones. INTERPRETATION OF SHALY FORMATIONS The readings of many logs are affected by shaliness. The shalier a sand, the greater the effect. The formations named in the preceding paragraph can be productive with up to 50 per cent (by volume) of shale. Before any meaningful evaluation of these reservoirs is possible, a shaliness adjustment must be made. Shale, as seen by logs, consists of two components, silt and clay.(1) Silt is a very fine-grained lime, quartz, dolomite or other material that has infinite resistivity and may be radioactive. Clay is a hydrated mineral that is usually radioactive and has a low resistivity due to its ion-exchange properties. Both of these shale constituents affect log readings. Assuming the source rock to be sandstone, shaliness will cause the effects listed in the following table. (Table in full paper) In addition, the sonic and neutron logs are affected in sand-shale sequences by gas, which causes the sonic to read high and the neutron to read low. Lack of formation compaction also causes the sonic to read high. Log readings must be adjusted for shaliness effect, presence of gas, lithology and compaction before they can be used for accurate analysis. In the following examples, it is shown that an interpretation based on a single porosity log or a gamma-ray neutron log is not adequate for shaly formations.

Effect of Clay and Water Salinity on Electrochemical Behavior of Reservoir Rocks

Published in Petroleum Transactions, Volume 207, 1956, pages 65–72. Abstract In quantitative interpretation of electrical logs the presence of clay minerals introduces an additional variable which further complicates an already complex problem. Although recognizing the difficulties introduced as a result of the heterogeneity of natural sediments and despite the present incomplete state of knowledge regarding electrochemical behavior of shades, disseminated clay minerals and concentrated electrolytes, it was felt that useful empirical correlations might be obtained from experimental investigation. Six typical sandstone formations, having a wide variety of petrophysical properties, were selected for the study. Approximately 45 samples from each formation were selected to satisfactorily represent the range of pore size distribution within the particular formation. As a matter of general interest, four limestone formations were also included in the investigation. Previously proposed equations relating to resistivity, SP and interrelationship of the two phenomena have, where possible, been tested with data obtained in this investigation. These equations do not satisfactorily describe experimental behavior of samples through all degrees of shaliness or throughout the range of brine solution resistivities normally encountered in logging practice. An empirical equation has been developed which quantitatively relates formation resistivity factor to saturating solution resistivity, porosity, and "effective clay content." This relation is indicated to be uniformly applicable to clean or shaly reservoir rocks. It is shown that both the SP and resistivity phenomena of shaly samples are related to the sample cation exchange capacity per unit pore volume. The independent chemical determination of this parameter is thus a means of determining the "effective clay content" of samples. Some implications regarding theory and electric log interpretation of shaly sands are discussed. Introduction The use of electrical resistivity logs as a means for estimating formation porosity is based upon the original work of Archie.