Oil Recovery In Carbonate Reservoirs Research Articles

Effect of Salinity and Water Ions on Electrokinetic Interactions in Carbonate Reservoir Cores at Elevated Temperatures

Summary Smartwater flooding through tailoring of injection-water salinity and ionic composition is becoming an attractive proposition for improved oil recovery in carbonate reservoirs. Most recent studies suggest that surface-charge change induced by lower salinity and certain water ions on carbonate surfaces is the main mechanism responsible for favorable wettability alteration and, consequently, higher oil recovery in smartwater flooding. Unfortunately, these studies determined ζ-potentials using the technique of electrophoretic-mobility (EPM) measurement with powdered-crushed-core samples, which may not reflect the natural conditions existing in the subsurface reservoirs. In this study we used an experimental technique dependent on streaming-potential (SP) measurements to determine ζ-potentials in intact carbonate reservoir core samples saturated with different brine salinities and individual ion compositions at both ambient and elevated temperatures. The results indicated a favorable effect of sulfate ions in carbonate reservoir cores to alter ζ-potentials toward more negative, and the reactivity of these ions increased significantly by nearly one order of magnitude at higher temperatures. Among the positive ions, calcium showed the highest reactivity to shift the ζ-potentials to slightly positive. Both magnesium and sodium ions showed almost similar behavior to change the ζ-potentials toward less negative. In addition, only minor to moderate changes in ζ-potentials were observed with the positive ions when the temperature is increased. In view of considering the reported negative ζ-potentials at the carbonate crude-oil/brine interfaces, such a change in ζ-potential to an extreme negative obtained in carbonate reservoir cores upon exposure to injection waters containing sulfates could have a favorable effect on wettability alteration because of the resulting same polarity at both the interfaces. The dynamic time-dependent effects on ζ-potentials measured during the displacement of seawater by smartwater (10-times-reduced ionic strength seawater) in reservoir cores showed an immediate shift in the ζ-potential value from positive to negative. This instantaneous change to negative values observed in the ζ-potentials confirms the beneficial effect of smartwater to activate favorable electrokinetic interactions in carbonate reservoir cores.

Low salinity waterflooding for a carbonate reservoir: Experimental evaluation and numerical interpretation

Several laboratory studies and some field trials have already demonstrated the potential of lowering the injected brine salinity and/or manipulating composition to improve oil recovery in carbonate reservoirs. Laboratory SCAL tests such as coreflooding and imbibition are key steps to screen low salinity waterflood (LSF) for a particular field to (i) ensure that there is LSF response in the studied rock/oil/brine system, (ii) find the optimal brine salinity, (iii) extract relative permeability curves to be used in the reservoir simulation model and quantify the benefit of LSF and (iv) examine the compatibility of injected brine with formation brine and rock to de-risk any potential scaling or formation damage caused by fines mobilization.This paper presents an extensive LSF SCAL study for a carbonate reservoir and the numerical interpretation of the tests. The SCAL experiments were performed at reservoir conditions using reservoir core plugs, dead crude oil and synthetic brines. The rock was characterized using porosity-permeability measurement semi-quantitative, X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury intrusion capillary pressure (MICP) techniques. The characterization work showed that the plugs can be classified into two groups (uni-modal and bi-modal) based on pore throat size distribution which correlated with porosity-permeability cross-plots.The SCAL experiments were divided in two categories. Firstly, spontaneous imbibition and qualitative unsteady-state (USS) experiments were performed to demonstrate the effect of low salinity brines. In addition, these experiments helped to screen different brines (seawater and different dilutions of seawater) in order to choose the one that showed the most promising effect. Secondly, quantitative unsteady-state (USS) experiments were conducted and interpreted using numerical simulation to extract relative permeability curves for high salinity and low salinity brines by history-matching production and pressure data.The main conclusions of the study are: 1- The spontaneous imbibition and qualitative USS experiments showed extra oil production when switching from formation brine to seawater or diluted seawater subsequently, 2- Oil recovery by LSF can be maximized by injection of brine at a certain salinity threshold, at which lowering the brines salinity further did not lead to additional recovery improvement, 3- The LSF effect and optimal brine salinity varied in different layers of the reservoir which indicates that within the same reservoir the LSF effect is quite dependent on the rock type/property and mineralogy, 4- The quantitative USS showed that LSF can improve the oil recovery factor by up to 7% at core scale compared to formation brine injection.

Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives

A significant fraction of the conventional oil reserves globally is in carbonate formations which contain a substantial amount of residual oil. Since primary and secondary recovery methods fail to yield above 20%–40% of original oil in place from these reserves, the need for enhanced oil recovery (EOR) techniques for incremental oil recovery has become imperative. With the challenges presented by the highly heterogeneous carbonate rocks, evaluation of tertiary-stage recovery techniques including chemical EOR (cEOR) has been a high priority for researchers and oil producers. In this review, the latest developments in the surfactant-based cEOR techniques applied in carbonate formations are discussed, contemplating the future direction of existing methodologies. In connection with this, the characteristics of heterogeneous carbonate reservoirs are outlined. Detailed discussion on surfactant-led oil recovery mechanisms and related processes, such as wettability alteration, interfacial tension reduction, microemulsion phase behavior, surfactant adsorption and mitigation, and foams and their applications is presented. Laboratory experiments, as well as field study data obtained using several surfactants, are also included. This extensive discussion on the subject aims to help researchers and professionals in the field to understand the current situation and plan future enterprises accordingly.

Dissolution of Rock During Smart Water Injection in Heavy Oil Carbonate Reservoirs by Natural Generation of Acidic Water

Smart waters have been studied for enhanced oil recovery in carbonate reservoirs, gaining significant attention from research groups and oil industry companies. However, there is a general consensus that the complexity of the fluids/rock system governs their effects, much fundamental knowledge is lacking, and many questions and uncertainties remain. For instance, the existence of rock dissolution in carbonate rocks, as a mechanism for oil production, has previously been documented. This work specifically focused on the interaction oil–brine–rock and its effect on rock dissolution. Carbonate rocks (limestones and dolomites), brines, and heavy crude oils were individually analyzed and then systematically mixed with each other to gain a comprehensive understanding of their interactions. Five heavy crude oils with different properties were tested under similar reservoir conditions (≈92 °C). Results revealed the generation of acidic water derived from the interaction between injected fluids and crude oils. Not all crude oils could produce acidic water, which is the cause of rock dissolution. This research suggests that the chemical interaction between crude oil and injected water may be one of the main reasons for the increased efficiency in response to the use of the smart waters for the improvement of oil production. Basic analyses that are presented here essentially provide an insight into the impact of the chemical interaction between crude oil and injection water with the rock. Finally, coreflood experiments were performed using a dolomitic core in order to monitor and verify the presence of dissolution during the flow of fluids. A basic crude oil was selected for this purpose. Effluent analysis, pH measurements, and permeability evaluations corroborated the influence caused by smart water injection as acidic water in contact with the rock. The findings of these experiments prove that is possible to predict and control the occurrence of the dissolution, observing interactions of crude oil and injection water.

Surface complexation modeling of calcite zeta potential measurements in brines with mixed potential determining ions (Ca2+, CO32−, Mg2+, SO42−) for characterizing carbonate wettability

This study presents experiment and surface complexation modeling (SCM) of synthetic calcite zeta potential in brine with mixed potential determining ions (PDI) under various CO2 partial pressures. Such SCM, based on systematic zeta potential measurement in mixed brines (Mg2+, SO42−, Ca2+ and CO32−), is currently not available in the literature and is expected to facilitate understanding of the role of electrostatic forces in calcite wettability alteration. We first use a double layer SCM to model experimental zeta potential measurements and then systematically analyze the contribution of charged surface species. Calcite surface charge is investigated as a function of four PDIs and CO2 partial pressure. We show that our model can accurately predict calcite zeta potential in brine containing a combination of four PDIs and apply it to predict zeta potential in ultra-low and pressurized CO2 environments for potential application in enhanced oil recovery in carbonate reservoirs. Model prediction reveals that calcite surface will be positively charged in all considered brines in pressurized CO2 environment (>1atm). The calcite zeta potential is sensitive to CO2 partial pressure in the various brine in the order of Na2CO3>Na2SO4>NaCl>MgCl2>CaCl2 (Ionic strength=0.1M).

Exploring beneficial structural features of ionic surfactants for wettability alteration of carbonate rocks using QSPR modeling technique

Surfactant induced wettability alteration of reservoir rocks is an efficient process that enhances oil recovery of carbonate reservoirs. Finding a suitable surfactant for such a process is an interesting challenge in petroleum industry. To this purpose, generating a database of surfactant properties would be a good idea but property measurement of hundreds of surfactants and then screening them is a highly time consuming and expensive method. Therefore, the application of a mathematical model for prediction of surfactant properties may well be so helpful for our purpose. Quantitative structure-property relationship (QSPR) is a mathematical model that relates a specific property of materials to their structural characteristics. For the sake of QSPR modeling a dataset of 24 structurally different surfactants was created through the measurement of contact angles (as the most important surfactant characteristic in the wettability alteration process). Contact angle measurement was carried out through imaging a drop of n-decane as the model oil resting on a carbonate rock which has spent 2days immersed in surfactant solution. For this dataset a linear QSPR model of oil contact angle on carbonate rocks was derived using genetic algorithm based on multi-linear regression (GA-MLR) and verified by internal and external validation metrics. From a descriptive point of view, descriptors of the proposed model have a mechanistic interpretation and give an insight to the desired structural features enhancing wettability alteration ability of surfactants.

Enhanced Wettability Modification and CO2 Solubility Effect by Carbonated Low Salinity Water Injection in Carbonate Reservoirs

Carbonated water injection (CWI) induces oil swelling and viscosity reduction. Another advantage of this technique is that CO2 can be stored via solubility trapping. The CO2 solubility of brine is a key factor that determines the extent of these effects. The solubility is sensitive to pressure, temperature, and salinity. The salting-out phenomenon makes low saline brine a favorable condition for solubilizing CO2 into brine, thus enabling the brine to deliver more CO2 into reservoirs. In addition, low saline water injection (LSWI) can modify wettability and enhance oil recovery in carbonate reservoirs. The high CO2 solubility potential and wettability modification effect motivate the deployment of hybrid carbonated low salinity water injection (CLSWI). Reliable evaluation should consider geochemical reactions, which determine CO2 solubility and wettability modification, in brine/oil/rock systems. In this study, CLSWI was modeled with geochemical reactions, and oil production and CO2 storage were evaluated. In core and pilot systems, CLSWI increased oil recovery by up to 9% and 15%, respectively, and CO2 storage until oil recovery by up to 24% and 45%, respectively, compared to CWI. The CLSWI also improved injectivity by up to 31% in a pilot system. This study demonstrates that CLSWI is a promising water-based hybrid EOR (enhanced oil recovery).

Novel fluorinated surfactants for enhanced oil recovery in carbonate reservoirs

Novel surfactant‐polymer (SP) formulations containing fluorinated amphoteric surfactant (surfactant‐A) and fluorinated anionic surfactant (surfactant‐B) with partially hydrolyzed polyacrylamide (HPAM) were evaluated for enhanced oil recovery applications in carbonate reservoirs. Thermal stability, rheological properties, interfacial tension, and adsorption on the mineral surface were measured. The effects of the surfactant type, surfactant concentration, temperature, and salinity on the rheological properties of the SP systems were examined. Both surfactants were found to be thermally stable at a high temperature (90 °C). Surfactant‐B decreased the viscosity and the storage modulus of the HPAM. Surfactant‐A had no influence on the rheological properties of the HPAM. Surfactant‐A showed complete solubility and thermal stability in seawater at 90 °C. Only surfactant‐A was used in adsorption, interfacial tension, and core flooding experiments, since surfactant‐B was not completely soluble in seawater and therefore was limited to deionized water. A decrease in oil/water interfacial tension (IFT) of almost one order of magnitude was observed when adding surfactant‐A. However, betaine‐based co‐surfactant reduced the IFT to 10−3 mN/m. An adsorption isotherm showed that the maximum adsorption of surfactant‐A was 1 mg per g of rock. Core flooding experiments showed 42 % additional oil recovery using 2.5 g/L (2500 ppm) HPAM and 0.001 g/g (0.1 mass%) amphoteric surfactant at 90 °C.

Modeling Low-Salinity Waterflooding in Chalk and Limestone Reservoirs

The injection of low-salinity brines can improve oil recovery in carbonate reservoirs by changing the rock wettability from being more oil-wet to being more water-wet. Existing models use an empirical dependence of wettability based on variables including equivalent salinity and ionic strength. We recently developed a process-based model that mechanistically includes the geochemical interactions between crude oil, brine, and the chalk surface that alter rock wettability. In this research, we extend the previous model by including mineral dissolution reactions, therefore enabling the modeling of low-salinity flooding in chalks and limestone cores with and without anhydrite, which is considered to be a key factor in controlling the extent of improved oil recovery (IOR). We examine the role of mineralogy by including surface complexation, aqueous reactions, and dissolution/precipitation of calcite and anhydrite in the extended model. These reactions, coupled with the equations of multiphase flow and transpor...

A Laboratory Investigation of the Effects of Temperature, Hardness, Surfactants, and Alkaline on Oil Recovery from Carbonate Reservoirs Using Spontaneous Imbibition Tests

More than 50 % of the known petroleum reserves are stuck in carbonate reservoirs, which can be divided into limestone, chalk, and dolomite. On average, the oil recovery from carbonates is below 30 % due to low water wetness, natural fractures, low permeability, and inhomogeneous rock properties. Therefore, there is increasing interest to improve oil recovery from carbonate reservoirs, as we are challenged to make up depleted reserves. Although there is a great potential to improve oil recovery in carbonate reservoirs, the research in this area is very limited due to technical and economic challenges. Chemical enhanced oil recovery research in carbonate reservoirs has been focused on using such as surfactant and alkaline increase oil recovery or to change oil-wet to more water-wet to enhance water imbibition into matrix blocks. Wettability alteration results in spontaneous imbibition of water into oil containing matrix, thus driving oil out of the matrix. Wettability alteration has been formulated with surfactant adsorption, and relative permeability and capillary curves are modified based on the degree of wettability alteration. Many research has been investigated in a lab scale how a wettability of reservoir rocks affected in oil recovery and how wettability alteration can be controlled to maximize the oil recovery in limestone rocks. The objective of this study is to investigate the effects of temperature, hardness, surfactants, and alkaline on oil recovery from limestone rock. In order to investigate the effect of these parameters, the limestone rocks were placed in the oven in brine to simulate realistic reservoir conditions. Then, they were aged in crude oil in the oven. After that, the solution with various compositions of surfactant, alkaline, and hardness were tested by spontaneous imbibition test. The spontaneous imbibition test in this study was performed at 25 oC and 80 oC with different limestone rocks. The results show that, at high temperature, the oil recovery is higher than at low temperature. The hardness has various impacts on the wetting properties. and are important in changing wettability on limestone surface and were proved by increase in oil recovery. ion was demonstrated by the very small increase in oil recovery. The alkaline has increased oil recovery from limestone rocks.

An Experimental Investigation into the Impact of Sulfate Ions in Smart Water to Improve Oil Recovery in Carbonate Reservoirs

Carbonate reservoirs are considered to be in the range of mixed to oil wetting state. Their present wetting state seems unfavorable to recover more oil via conventional waterflooding especially as the water cut increases with huge residual oil saturation. In recent years, studies have shown that tuning the injected brine chemistry can help decrease the oil-wetness, resulting in additional oil recovery and reduction in residual oil saturation. Thus, rock wettability is being dictated by the surface chemistry associated with the water-film stability between crude oil and the rock surface. This study presents series of experiments conducted on Middle Eastern carbonate core plugs at high pressure and high temperature in order to determine the impact of sulfate ions in smart brine on oil recovery. Each experiment was initially conducted using the formation brine, and subsequently, various versions of seawater with varying sulfate concentrations were used. Coreflooding experiments showed an additional recovery of about 7–9 % oil originally in core when sulfate concentration was increased while none when decreased. Decrease in rock oil-wetness was observed to be responsible for the improved recovery as demonstrated by the contact angle analysis. Similar trend was observed with the zeta potential analysis which further proved that the magnitude of surface charge alteration contributes immensely to wettability modification toward more water-wetness.

Enhanced heavy oil recovery for carbonate reservoirs integrating cross-well seismic – A synthetic Wafra case study

Abstract Heavy oil recovery has been a major focus in the oil and gas industry to counter the rapid depletion of conventional reservoirs. Various techniques for enhancing the recovery of heavy oil were developed and pilot-tested, with steam drive techniques proven in most circumstances to be successful and economically viable. The Wafra field in Saudi Arabia is at the forefront of utilizing steam recovery for carbonate heavy oil reservoirs in the Middle East. With growing injection volumes, tracking the steam evolution within the reservoir and characterizing the formation, especially in terms of its porosity and permeability heterogeneity, are key objectives for sound economic decisions and enhanced production forecasts. We have developed an integrated reservoir history matching framework using ensemble based techniques incorporating seismic data for enhancing reservoir characterization and improving history matches. Examining the performance on a synthetic field study of the Wafra field, we could demonstrate the improved characterization of the reservoir formation, determining more accurately the position of the steam chambers and obtaining more reliable forecasts of the reservoir’s recovery potential. History matching results are fairly robust even for noise levels up to 30%. The results demonstrate the potential of the integration of full-waveform seismic data for steam drive reservoir characterization and increased recovery efficiency.

Wettability Modifier for Enhanced Oil Recovery in Carbonate Reservoir: An Overview

This article is an overview of potential application of wettability modifier to enhance oil recovery in carbonate reservoir. In oil and gas industry, oil recovery can be divided into three stages which are primary recovery, secondary recovery and tertiary recovery. The primary recovery is the initial stages of oil recovery. At this stage, oil was displaced toward production well by natural drive mechanisms that naturally exist in the reservoir. Water is commonly used to enhance oil recovery by injected into the reservoir because of it is commercially available, less expensive and capable to maintain the reservoir pressure. In conclusion, smart water flooding is a new technique to solve the complexity problem of carbonate reservoir by manipulating the salinity and ionic composition in high temperature. Hence, smart water can be an excellent candidate as a displacing fluid in chemical flooding for enhanced the oil recovery (EOR).

Experimental investigation of SiO2 nanoparticles on enhanced oil recovery of carbonate reservoirs

Wettability alteration is an important method to increase oil recovery from oil-wet carbonate reservoirs. Chemical agents are used as wettability modifiers in carbonate systems; however, the role of Nanoparticles in this field is still in its infancy and consequently has attracted the attention of many researchers in the last decade. In this work, the impact of SiO2 Nanoparticles on the wettability of a carbonate reservoir rock was experimentally studied. The impact of these Nanoparticles on the wettability of carbonate systems is still in its infancy. For this purpose, the effect of Nanofluid’s concentration on wettability and interfacial tension were investigated to determine the optimum concentration of Nanofluid for injection into core samples. The result suggests that a concentration of 4 g/L of Nanofluid could significantly alter the wettability of the rock from a strongly oil-wet to a strongly water-wet condition. Moreover, we studied the Nanofluids’ potential in enhanced oil recovery of oil-wet core plugs. The results show that a considerable amount of oil can be recovered right after start of water injection to the aged core plug with Nano fluid.

Review of Surfactant Enhanced Oil Recovery in Carbonate Reservoirs

About half of proven conventional oil reserves are in carbonate reservoirs. Due to complex structures, formation heterogeneities and oil-wet/mixed wet conditions, etc., the oil recovery factor in carbonate reservoirs is very low. There is increasing interest in improve oil recovery using surfactants, as the surfactant EOR has the potential after other EOR methods have been tried. This paper reviews the models of wettability alteration using surfactants and upscaling models related to oil recovery in carbonate reservoirs. Chemicals used in carbonate reservoirs are reviewed. The field cases where surfactants were used to stimulate oil recovery are analyzed. Key words: Enhanced oil recovery; Carbonate reservoirs; Wettability alteration; Chemical EOR

An Evaluation for Two Bacillus Strains in Improving Oil Recovery in Carbonate Reservoirs

Many successful field cases of microbial enhanced oil recovery (MEOR) method have been reported for sandstone reservoirs. The objective of this study is to investigate the potential of MEOR method in UAE carbonate reservoirs. Two Bacillus strains were incubated at temperatures from 35 to 55°C, and their effects on crude oil properties and recovery were examined. It was discovered the strain could effectively reduce interfacial tension. Bacteria solutions were subsequently injected into a glass Hele-Shaw model to simulate microbial flooding in a fracture. It was observed that both strains grown under 45°C achieved maximum enhanced recovery of over 13%. Core flooding tests were conducted at elevated temperature of 70°C with limestone core. The two strains achieved enhanced oil recovery of more than 4.5%. The observation on core flooding test indicated selective plugging as the dominant recovery mechanism.

Comparison of the effects of wettability alteration and IFT reduction on oil recovery in carbonate reservoirs

ABSTRACTInjection of chemicals in a carbonate reservoir may change wettability and reduce interfacial tension (IFT). The question is how much each mechanism contributes to the increase in oil recovery. There is lack of such information in the literature. The information is very important because it will guide us to select which chemicals to use, as some chemicals can effectively reduce IFT, whereas others can change wettability.This paper aims to compare the effects of different mechanisms in oil recovery related to chemical enhanced oil recovery (EOR) . Particularly, we compare the effects of wettability alteration and IFT reduction. Numerical simulation models are used. Our results show that wettability alteration plays important roles when IFT is high, and it is effective in the early time. IFT plays very important roles with or without wettability alteration and is effective during the entire process. Note that the matrix permeability is reasonably high so that the fluids can be redistributed. The implication is that anionic surfactants are preferred to cationic surfactants in chemical EOR, as the former are generally used to reduce IFT, whereas the latter are used to change wettability. Other observations are that in surfactant‐induced wettability alteration with low IFT, gravity drive is a very important mechanism. Molecular diffusion of chemicals affects oil recovery rate in the early time, but not ultimate oil recovery. © 2012 Curtin University of Technology and John Wiley & Sons, Ltd.

Applicability Test of New Surfactant Produced from Zizyphus Spina-Christi Leaves for Enhanced Oil Recovery in Carbonate Reservoirs

After the primary production period, water flooding is usually performed to recover more oil from reservoirs. However, water flooding recoveries are low from naturally fractured carbonate reservoirs, due in part to these reservoirs being mixed to oil-wet. Most of Iranian reservoirs are naturally fractured. Chemical process and especially surfactant flooding is an interested method because of its effect on interfacial tension (IFT) reduction and wettability alteration. Different surfactants are used for chemical flooding in the world but these chemical have high price and some detrimental effect on the environment. In this paper a new nonionic biosurfactant which is produced from the leaves of special tree called Zizyphus Spina-Christi is introduced. There is a hypothesis that this surfactant can be used in chemical flooding of fractured reservoirs because of very low cost and availability in Middle-East and Africa compared to other currently used surfactants. For this purpose surfactant is extracted from the leaves by spray dryer method. The pendant drop method is used to measure interfacial tension and critical micelle concentration (CMC) values. In order to investigate the effect of this surfactant on oil recovery two series of imbibition experiments are conducted on water-wet and oil-wet samples. It is observed that oil recovery is about ∼16 % OOIP (original oil-in-place) for oil-wet cores by using this surfactant. In the same test, no oil is produced with water due to high oil wettability. After adding surfactant to the water, the oil recovery about ∼7 % OOIP is obtained. Other test is done on water-wet cores which shows that addition of surfactant reduce the ultimate recovery from ∼35 % OOIP to ∼12.5 % OOIP. Reducing interfacial tension cause decrease in imbibition drive mechanism and lower the ultimate recovery. These results indicate that this new type of surfactant can meet the technical requirements as enhanced oil recovery (EOR) agent for chemical flooding.

炭酸塩岩を対象とした貯留層特性把握と繰り返し地震探査

We are now executing a cooperative research project with UNOCAL in order to develop and apply geophysical technology for reservoir characterization and optimizing miscible flood enhanced oil recovery in carbonate reservoirs. This project aims to monitor the fluid behavior in carbonate reservoirs by time-lapse geophysical surveys such as 3-D seismic survey, VSP, cross-well technology and well logging. JNOC and UNOCAL decided to conduct this study at the Reinecke oil field in Texas, U.S.A., operated by UNOCAL, whose reservoir is Paleozoic dolomitic limestones.First, we interpreted the geometrical framework of the reservoir and described the reservoir in terms of P-P reflected wave volume and P-SV converted wave volume, both of which were generated from the data acquired in December, 1997. Based on these methods, we drew a detailed time structure map and found some new structural/sedimentological features of the reservoir.Second, for reservoir characterization, we calculated the Vp/Vs ratio from the isochron P-P and P-SV 3D volumes and created a distribution map of the Vp/Vs ratio. We evaluated the distribution map as a predictive tool of carbonate lithology by using the relationship between the Vp/Vs ratio and the dolomite content established through well log analysis. Our initial interpretation suggests the correlation between the the seismically deduced Vp/Vs ratio and the dolomite content. There has been, however, difficulties in the evaluation at its advanced stage. Believing that such 3D seismic volume information should include some useful attributes of reservoir, we are continuing to evaluate the data for further reservoir characterization.Third, we conducted a new 3D survey over the field in December, 1999, after Unocal started to inject CO2 to the reservoir in January, 1998. This is to monior the effect of the CO2 injection using the seismic attributes in those time-lapse data series. We successfully found some differences in and around the reservoir between the previous baseline sections and the rush sections of the monitoring survey. This evaluation will be completed with cross-equalizing the volume data sets calculated from the two, time-lapse surveys.

Microbial composition of carbonate petroleum reservoir fluids

Abstract Production fluids from four single‐zone completion wells in carbonate petroleum reservoirs were examined chemically and microbiologically to investigate the potential for microbially enhanced oil recovery in carbonate reservoirs. The water analysis indicated a lack of soluble nitrogen and phosphorus in these reservoir fluids. Three of the wells were highly saline, as expected, but one produced water containing <0.5% sodium chloride. Microorganisms with metabolisms useful for microbially enhanced oil recovery were enriched from the highly saline water produced from these three wells. A small, but metabolically diverse, microbial community was detected in each of the produced water samples. Although reservoir temperatures ranged from 44 to 63 °C, the highest viable counts were obtained at mesophilic temperatures. The results from this study are consistent with a hypothesis that, physical conditions permitting, carbonate petroleum reservoirs contain microbial populations that could be stimulated for...