Fractured Limestone Reservoir Research Articles

Shear wave velocity prediction for fractured limestone reservoirs based on artificial neural network

AbstractShear wave velocity is an essential parameter in reservoir characterization and evaluation, fluid identification and prestack inversion. However, conventional data‐driven or model‐driven shear wave velocity prediction methods exhibit several limitations, such as lack of training data sets, poor model generalization and weak model robustness. In this study, a model‐ and data‐driven approach is presented to facilitate the solution of these problems. We develop a theoretical rock physics model for fractured limestone reservoirs and then use the model to generate synthetic data that incorporates geological and geophysical knowledge. The synthetic data with random noise is utilized as the training data set for the artificial neural network, and a well‐trained shear wave velocity prediction model, random noise shear wave velocity prediction neural network, is established by parameter tuning, which fits the synthetic data with noise well. The neural network is applied directly to the real field area. Compared with conventional shear wave prediction methods, such as empirical formulas and the improved Xu–White model, the prediction results show that the random noise shear wave velocity prediction neural network has better prediction performance and generalization. Furthermore, the prediction results demonstrate the efficacy of the proposed approach, and the approach has the potential to perform shear wave velocity prediction in real areas where training data sets are unavailable.

Towards prediction of oil recovery by spontaneous imbibition of modified salinity brine into limestone rocks: A scaling study

Spontaneous imbibition is a key mechanism of oil recovery in naturally fractured reservoirs. Many enhanced oil recovery techniques, such as modified salinity brine injection, have been suggested to improve spontaneous imbibition efficiency. To predict oil recovery by spontaneous imbibition process, scaling equations have been developed in the literature where almost none of them include the effect of two critical aspects. One aspect is the different ionic composition of injecting brine from connate brine. Another aspect is the effect of combination/interaction of a lower salinity imbibing (injecting) brine with connate brine. This research takes into account these two aspects to propose a new empirical scaling equation to scale oil recovery by modified salinity imbibing brines in limestone rocks. For this purpose, the results of available 59 tests from 14 references performed on various limestone rock samples collected from different formations and regions were used. The tests had been performed at high temperatures and on aged cores, which makes the proposed scaling equation more realistic and applicable to reservoir conditions. For the first time, the imbibing and connate brines ionic strengths are included in the equation due to the mechanism of the modified salinity brine injection method. In addition, the scaled spontaneous imbibition recovery data by the new equation was matched using two mathematical expressions based on the Aronofsky model and Fries and Dreyer model which can be used to derive transfer functions for simulation of spontaneous imbibition oil recovery by modified salinity brine injection in fractured limestone reservoirs.

RATANA FIELD, POTWAR FOLD BELT, NORTHERN PAKISTAN: HIGH INTENSITY FRACTURE ZONES RELATED TO MAJOR THRUST FAULTS AS REVEALED BY SEISMIC FRACTURE PREDICTION

The Northern Potwar Deformed Zone (NPDZ) of the frontal Himalayas in northern Pakistan hosts many oil and gas fields located in thrust sheets and associated folds. The presence of fractures in Paleogene carbonates at >3 km target depths with very little or no primary porosity is an essential part of reservoir storage and connectivity. Predicting fracture presence, distribution and orientation is therefore key to successful exploration, appraisal and field development in the NPDZ.The Ratana field is an under‐developed fractured carbonate reservoir in the NPDZ. Advanced offset vector tile (OVT) PSTM and PSDM processing of a new generation of wide azimuth 3D seismic acquired across the field followed by seismic attribute generation and fracture modelling was used to investigate structural complexities and image fracture networks. Fracture strike characteristics are revealed by PSDM seismic attributes, OVT fracture prediction, FMS/FMI data and structural interpretation across a range of scales. The resulting seismic images show the presence of major WNW‐ESE trending back thrusts which cross the field, and predict that steeply‐dipping fracture systems are spatially associated with these thrusts. The strike of the OVT‐predicted fractures is consistent with the regional trend of the Ratana field bounding thrusts, as well as with the orientation of fractures indicated from FMI/FMS logs. Fractured reservoir is best developed in the Paleocene Patala and Lockhart Formation limestones but is poor in the Eocene Sakesar Formation. Fractured limestone reservoirs occur in the western part of the field where thrust intensity is high, but are less well developed in the gently folded anticline in the eastern part of the field. OVT fracture prediction surface maps are consistent with production data from the field in that areas of high fracture intensity in wells Ratana‐2 and Ratana‐4 are associated with higher production compared to the less well fractured areas around the Ratana‐1 and Ratana‐3 wells.The advanced seismic acquisition and processing is thus an exceptional example of a step change in seismic imaging at the reservoir and deeper levels, enabling compartment and fracture prediction to provide the Ratana field with a new lease of life. This fracture prediction approach provides a new structural framework for further exploration across the NPDZ and also potentially in other onshore fold‐and‐thrust belts.

Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-md Limestone

SummaryThe high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-md formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions.The low-IFT foam process was investigated through coreflood experiments in homogeneous and fractured oil-wet cores with sub-10-md matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer [alpha olefin sulfonate (AOS) C14-16] were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the coreflood experiments.Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-md matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-md matrix permeability achieved 64% incremental oil recovery compared to waterflooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, the foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluid flow in the matrix. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of the low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids—such as mineral dissolution and the exchange of calcium and magnesium—were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It, therefore, may cause injectivity and phase-trapping issues especially in the homogeneous limestone.Results in this work demonstrated that despite the challenges associated with limestone dissolution, the low-IFT foam process can remarkably extend chemical enhanced oil recovery (EOR) in fractured oil-wet tight reservoirs with matrix permeability as low as 5 md.

Description of the Results of Experiments on Developed Miscibility With Nonequilibrium Gas/Oil Gravity Drainage

Summary This paper describes the results of several experiments that were carried out to investigate the block-to-block interaction in fractured limestone reservoirs for both gas/oil and solvent/oil systems by use of carbonate cores. The focus of this research was to understand gravity drainage, reinfiltration, and mixing in fractured systems with a set of laboratory experiments. The designed setup included three kinds of models (i.e., a transparent rectangular box filled with a glass-bead pack and two cylindrical models with single and stacked carbonate blocks inside to cover all important cases in this area); then, several factors are defined to correlate the results of glass-bead-pack model with the two other kinds of models. Also, the survey of the experiments and the properties of the fluids used takes a relatively wide range of the applicable laboratory experiments to provide a better understanding of the mentioned mechanisms. In general, this paper can be very revealing to other researchers in the field because it provides some experimental data for future theoretical and simulation studies.

Hydro-geophysical characterization for groundwater resources potential of fractured limestone reservoirs in Amdoun Monts (North-western Tunisia)

This study has led to the identification of the Upper Cretaceous and Lower Eocene (Abiod, Boudabbous/El Gueria Formations) fractured and karstic aquifers in the Amdoun region (Northwestern Tunisia). Geological information (litho-stratigraphy and fractures network study) and geophysical (gravity, wells analysis, seismic reflection, Electrical Resistivity Tomography (ERT)) investigations performed in the area have highlighted, with some detail, images of structures of carbonate aquifers near anticline flanks and along perched synclines. Some factors such as fracture intensity, karsts evolution and structural position have an important influence on the hydrologic productivity of Abiod and Boudabbous/El Gueria reservoirs. Different methodologies were used to characterize the geological and hydro-geological perched aquifers and produce the 3D geo-electrical model of near surface karstic features and cavities of the carbonate limestone in the Aïn Sallem site. This study integrates the geological and geophysical information available and can serve as a representative example in the description of the most important hydraulic reserves in the North-western Tunisia.

Wettability alteration of oil-wet carbonate by silica nanofluid

Changing oil-wet surfaces toward higher water wettability is of key importance in subsurface engineering applications. This includes petroleum recovery from fractured limestone reservoirs, which are typically mixed or oil-wet, resulting in poor productivity as conventional waterflooding techniques are inefficient. A wettability change toward more water-wet would significantly improve oil displacement efficiency, and thus productivity. Another area where such a wettability shift would be highly beneficial is carbon geo-sequestration, where compressed CO2 is pumped underground for storage. It has recently been identified that more water-wet formations can store more CO2.We thus examined how silica based nanofluids can induce such a wettability shift on oil-wet and mixed-wet calcite substrates. We found that silica nanoparticles have an ability to alter the wettability of such calcite surfaces. Nanoparticle concentration and brine salinity had a significant effect on the wettability alteration efficiency, and an optimum salinity was identified, analogous to that one found for surfactant formulations. Mechanistically, most nanoparticles irreversibly adhered to the oil-wet calcite surface (as substantiated by SEM–EDS and AFM measurements). We conclude that such nanofluid formulations can be very effective as enhanced hydrocarbon recovery agents and can potentially be used for improving the efficiency of CO2 geo-storage.

Investigation of permeability alteration of fractured limestone reservoir due to geothermal heat extraction using three-dimensional thermo-hydro-chemical (THC) model

Heat extraction by cold water circulation disturbs the thermo-chemical equilibrium of a geothermal reservoir, activating the dissolution/precipitation of minerals in the fractures. Calcite being a more reactive mineral than other rock minerals composing the earth curst, we investigate the permeability alteration during geothermal heat production from carbonate reservoirs. In this study the simulations are performed using the code FEHM with coupled thermo-hydro-chemical (THC) capabilities for a three dimensional domain. The computational domain consists of a single fracture connecting the injection and production wells. For reactive alteration of aperture, the model considers that the kinetics of dissolution/precipitation is coupled to the equilibrium interactions among the aqueous species/ions. The reaction rate predominantly depends on the temperature dependent solubility and advective–dispersive solute transport in the fracture. Due to the nonuniform flow fields resulting from injection and production, the coupled thermo-hydro-chemical processes initiate significant variation of the aperture alteration rate over the fracture. We have considered different operating conditions such as different mass injection rate, injection temperature and concentration of minerals. Our simulations show that dissolution and precipitation can occur simultaneously at different locations in fracture. Furthermore the reaction rate varies with time and the reaction rate can also switch between dissolution and precipitation. To illustrate this interesting behavior, the variations of shape and size of zero reaction rate contours with time are shown. An interesting outcome is a non-monotonic evolution of the overall transmissivity between the wells. The alteration of overall transmissivity largely depends on the concentration of mineral in the injected water with respect to the solubility at the initial fracture temperature. For both dissolution and precipitation controlled cases, the rapid changes in transmissivity provide challenges for maintaining circulation of water at constant mass flow rate.

Unique CO2-Injection Experience in the Bati Raman Field May Lead to a Proposal of EOR/Sequestration CO2 Network in the Middle East

Summary Carbon capture and storage (CCS) is one of the most important emission-reduction technologies available for large stationary CO2 sources. Fossil-fueled power generation is the largest source of carbon dioxide (CO2) that could be captured and stored. Depleted oil and gas fields and major CO2 sources nearby are ideal places for large-scale geological storage. Injection of CO2 into a depleted reservoir can enhance the recovery of hydrocarbons. The circumstances, in fact, dictate that the CO2 enhanced-oil-recovery (EOR) industry and power-generation sector should be eager to magnify the mutually beneficial link between CO2 EOR and new industrial sources of CO2. In 1986, the Turkish Petroleum Corporation (TPAO) started the first large-scale immiscible-CO2-injection project in southeastern Turkey. Approximately 1 million tons/yr of naturally occurring CO2 has been injected into Garzan carbonates in the Bati Raman field. A substantial increase in the production rate and ultimate recovery has been experienced, and this is expected to continue. The Bati Raman immiscible-CO2-injection project has been acknowledged as one of the most unique and successful EOR applications in the history of heavy oil in fractured-limestone reservoirs. There are nearly 50 oil fields in Turkey, and a significant proportion of them would be potentially suitable for EOR. If sufficient volumes of CO2 were economically available, many of these could produce incremental oil for an extended period. It is a fact that sedimentary basins in the Middle East are typically carbonates, and this limits the selection of EOR processes significantly. Having observed CO2 injection as an excellent choice for carbonates through experience with the Bati Raman field, one may extend the CO2 network idea to the whole region. This will not only activate the enormous EOR potential in the mature fields of the Middle East, but also the permanent storage of CO2 through a common effort. The use of captured CO2 for EOR will become feasible if CO2-recovery plants with a higher CO2 content give an attractive CO2 delivery cost and emission rights can be traded in the carbon market, which was introduced by the Kyoto protocol. The major challenges would be formulating a working and acceptable model between petroleum and power sectors and to establish a market mechanism to ensure that this system becomes economically feasible.

Effect of Fracture Compressibility on Oil Recovery From Stress-Sensitive Naturally Fractured Reservoirs

Abstract The tank material balance (MB) equation for undersaturated and saturated reservoirs has been written taking into account the effective compressibility of matrix and fractures. The solution is presented in finite difference form to achieve a quick convergence of the iteration process. Historically, compressibility has been neglected when carrying out MB calculations of conventional reservoirs producing below the bubble point. This assumes that the reservoir strata are static. It is shown however, that under some conditions, fracture compressibility can have a significant impact on oil rates and recoveries of naturally fractured reservoirs (NFRs) performing below the bubble point, as the fracture permeability and fracture porosity are stress-dependant. Other stress-sensitive properties discussed in this paper include the partitioning coefficient and the exponent for the shape of relative permeability curves. The use of the MB finite difference equations is illustrated with an example. Introduction Forecasting the performance of naturally fractured reservoirs (NFRs) is a major challenge. Various authors have tackled the problem throughout the years using MB calculations. To the best of my knowledge, the effect of fracture compressibility below the bubble point has been usually ignored in MB equations for saturated reservoirs. The work presented in this paper is not meant to replace a detailed reservoir simulation, which is the best way to try to solve the problem provided that reservoir characterization and quality of the pressure and production data is good. The objective is to have a tool that can provide a quick indication with respect to potential oil recoveries from stress-sensitive NFRs. Pirson(1) pioneered efforts to try to explain the high GOR associated with many NFRs once the bubble point is reached. He considered the reservoir to be made of two porosity and permeability systems in parallel and visualized production as a succession of equilibrium stages. Jones-Parra and Seijas-Reytor(2) studied the effect of gas-oil ratio on the behaviour of fractured limestone reservoirs using a two-porosity model. They assumed that gravity segregation took place freely and resistance to fluid flow was very small in the fracture network. In the matrix or fine porosity system, there was high resistance to flow and no segregation. Aguilera(3, 4) used combined log analyses and MB to try to explain the high gasoil ratios observed in many NFRs. More recently, Penuela et al.(5) presented a MB for calculating oil-in-place in matrix and fractures taking into account the compressibility difference between matrix and fractures. This paper presents MB equations for predicting oil recovery and rates of undersaturated and saturated reservoirs. The equations are written taking into account the effective compressibility of matrix and fractures. Stress-sensitive properties such as fracture porosity, fracture permeability, partitioning coefficient, and exponent for shape of relative permeabilities are taken into account. The solution is presented in finite difference form to achieve a quick convergence of the iteration process.

Spatial distribution of temperature in the low-temperature geothermal Euganean field (NE Italy): a simulated annealing approach

The spatial distribution of groundwater temperatures in the low-temperature (60–86 °C) geothermal Euganean field of northeastern Italy has been studied using a geostatistical approach. The data set consists of 186 temperatures measured in a fractured limestone reservoir, over an area of 8 km 2. Investigation of the spatial continuity by means of variographic analysis revealed the presence of anisotropies that are apparently related to the particular geologic structure of the area. After inference of variogram models, a simulated annealing procedure was used to perform conditional simulations of temperature in the domain being studied. These simulations honor the data values and reproduce the spatial continuity inferred from the data. Post-processing of the simulations permits an assessment of temperature uncertainties. Maps of estimated temperatures, interquartile range, and of the probability of exceeding a prescribed 80 °C threshold were also computed. The methodology described could prove useful when siting new wells in a geothermal area.

Fractal and cumulative trace analysis of wire-line logs from a well in a naturally fractured limestone reservoir in the Gulf of Mexico

Hemos demostrado que los registros de pozo medidos en un yacimiento carbonatado naturalmente fracturado tienen un carácter fractal, estando sus parámetros fractales correlacionados con las propiedades petrofísicas de los depósitos. Los registros de porosidad neutrón, densidad, rayos gamma, tiempo de transito de Ia onda P y resistividad somera y profunda, se relacionaron bien con cinco estratos: Jurasico Superior Tithoniano y Kimmeridgiano (JST, JSK), Cretácico Superior, Medio e Inferior (KS, KM, KI). Cada una de estas capas tiene dimensiones fractales diferentes. Utilizando el software BENOIT se ajustaron las trazas de los registros como movimientos Brownianos fraccionarios (fBm) obteniéndose dimensiones fractales promedio para el registro de porosidad D=l.70 (KS), D=1.66 (KM), D=1.75 (KI), D=1.84 (JST), D= 1.67 (JSK). Establecemos que la geometría fractal de los poros controla las fluctuaciones y dimensiones fractales de los registros en cada unidad geológica. El análisis de las trazas acumuladas ha proporcionado una mejor comprensión del sistema, incluyendo las cinco unidades principales.doi: sin doi

Abstract: Upper Cretaceous Abiod Fractured Limestone Reservoir In The Gulf Of Hammamet- North East Offshore Tunisia 

Abstract: Upper Cretaceous Abiod Fractured Limestone Reservoir In The Gulf Of Hammamet- North East Offshore Tunisia 

Pilot Application of a Blocking Agent - Weyburn Unit, Saskatchewan

Channelblock is a gelatinous blocking agent that permanently reduces channeling in waterflooding operations. It diverts injection water into the tighter zones and thus effects higher waterflood recovery. The pilot operation described here illustrates a successful application on the edge of a fractured limestone reservoir. Introduction The Weyburn Unit is situated in southeastern Saskatchewan and encompasses an area of approximately 100 sq miles. The field was discovered in Jan. 1955 and was extensively developed by drilling 675 wells on 80-acre spacing (Fig. 1). A distinctive feature of this Mississippian Midale Beds pool and of other fields in the same part of the province is the presence of an anisotropic permeability system whose major axis is oriented northeast-southwest (Fig. 2). This fracture system, which was first recognized on the basis of oriented fracture cores, has been clearly identified by waterflood performance. Oil accumulation in this stratigraphic trap is found mainly in the Midale beds of the Charles formation of Mississippian age. The oil reservoir is subdivided into two distinct lithological units; the upper is the Marly limestone, and the lower is the Vuggy limestone (Fig. 3). The Marly rock is a microgranular carbonate characterized by fairly uniform porosity averaging 26 percent and low permeability averaging 4 md. The percent and low permeability averaging 4 md. The Vuggy is generally microcrystalline, fragmental limestone with extreme variations in pore size and in porosity-permeability distribution. Porosity averages porosity-permeability distribution. Porosity averages 11 percent and the permeability may vary between 0.1 and 4,000 md. Oil gravity varies with structural position from a low of 26 degrees API at the southern position from a low of 26 degrees API at the southern downdip limit to a high of 35.6 degrees API at the highest structural position to the north. An inverted nine-spot injection pattern was selected for waterflooding this type of limestone reservoir. Such a pattern was chosen because it could easily be converted to a line drive or a staggered line drive either by suspending the uneconomical on-trend wells or by converting them to water injection service. Flood Performance The waterflood scheme was implemented in June 1964. The angle that the fracture plane forms with the line connecting adjacent producers and injectors is the most important factor affecting the flood performance of each producer. performance of each producer. Fig. 4 shows that the performance of an on-trend well is characterized by a premature water breakthrough, rapid oil decline, and a sharp increase in water production. For this category of wells the estimated production. For this category of wells the estimated total waterflood recovery is approximately 8 to 12 percent of the original oil in place. percent of the original oil in place. Fig. 5 illustrates the performance of an off-trend well belonging to the same injection pattern. There was a gradual response to the flood for 2 or 3 years, and then there appears to have been a long subordinate phase. phase. The Marly zone is generally not fractured. In this zone the values of the factors governing the flood are as follows: mobility ratio, 0.32; Lorenz coefficient, 0.45; and permeability variance, 0.55. The Vuggy pay is fractured and has an average mobility ratio, Lorenz coefficient, and permeability variance of 1.75, 0.78, and 0.87, respectively. Furthermore, the water and residual oil saturations in the Vuggy are higher than in the Marly, resulting in a lower flushing efficiency. JPT P. 973

Effect of Gas-Oil Ratio on the Behavior of Fractured Limestone Reservoirs

Abstract The porosities of fractured limestone reservoirs can be divided into two broad types in accordance with their effects on fluid distribution and fluid flow. In the coarse porosity, gravity segregation takes place freely and the resistance to fluid flow is very small. In the fine porosity there is no segregation and a high resistance to flow, and it has relative permeability characteristics similar to tight sandstones. By analyzing the affect of the two porosities it is concluded that in some cases to recover the maximum amount of oil it is necessary to remove large quantities of gas from the reservoir by producing at high gas-oil ratios. In this manner the fine porosity is drained of its oil and the gas-oil contact drops slowly permitting higher production rates from the oil leg. Since this conclusion is contrary to widely accepted principles of conservation, a mathematical model (Fig. 1) was constructed to duplicate the conditions desired. The behavior of the model indicates that under certain conditions it is possible to recover more oil by producing at high gas-oil ratios than by production at low gas-oil ratios, and that the rate of production is affected more by gas shut-offs than by the decrease in pressure (Figs. 2, 3, 4 and 5). Introduction It has been noted that certain limestone reservoirs behave in such a way as to indicate that there are two distinct types of porous spaces available for fluid storage and fluid flow. Regardless of the nature of these porous spaces the distinguishing characteristic is that in one type of porous space there is definite gravity segregation between the oil and the gas; while in the other, the gas evolved tends to remain distributed equally throughout the reservoir. For the sake of simplicity the porosity in which gravity segregation takes place at a fast enough rate to affect the behavior will be called "coarse porosity", while that in which this is not so will be termed "fine porosity".

Fracture Porosity in Gulf Coast

Little information on fracture porosity has been published on the Gulf Coast area. In one fractured limestone reservoir cited, intergranular porosity varies in permeability from bed to bed. Open fractures are detrimental rather than beneficial in being channels for bottom-water migration. A serpentine plug cited is highly fractured and fracture porosity has caused considerable increase in the total porosity. Fracturing is one step in the formation of salt-dome limestone cap-rock reservoirs such as Spindletop. Fracture porosity in competent and incompetent beds around the salt domes has not been evaluated.