Fractured Carbonate Oil Reservoir Research Articles

Study on Plugging Mechanism of Gel Plugging Agent in Fractured Carbonate Oil Reservoirs

Study on Plugging Mechanism of Gel Plugging Agent in Fractured Carbonate Oil Reservoirs

Enhancing the spontaneous imbibition rate of water in oil-wet dolomite rocks through boosting a wettability alteration process using carbonated smart brines

Most fractured carbonate oil reservoirs have oil-wet rocks. Therefore, the process of imbibing water from the fractures into the matrix is usually poor or basically does not exist due to negative capillary pressure. To achieve appropriate ultimate oil recovery in these reservoirs, a water-based enhanced oil recovery method must be capable of altering the wettability of matrix blocks. Previous studies showed that carbonated water can alter wettability of carbonate oil-wet rocks toward less oil-wet or neutral wettability conditions, but the degree of modification is not high enough to allow water to imbibe spontaneously into the matrix blocks at an effective rate. In this study, we manipulated carbonated brine chemistry to enhance its wettability alteration features and hence to improve water imbibition rate and ultimate oil recovery upon spontaneous imbibition in dolomite rocks. First, the contact angle and interfacial tension (IFT) of brine/crude oil systems were measured for several synthetic brine samples with different compositions. Thereafter, two solutions with a significant difference in WAI (wettability alteration index) but approximately equal brine/oil IFT were chosen for spontaneous imbibition experiments. In the next step, spontaneous imbibition experiments at ambient and high pressures were conducted to evaluate the ability of carbonated smart water in enhancing the spontaneous imbibition rate and ultimate oil recovery in dolomite rocks. Experimental results showed that an appropriate adjustment of the imbibition brine (i.e., carbonated smart water) chemistry improves imbibition rate of carbonated water in oil-wet dolomite rocks as well as the ultimate oil recovery.

A Semi-Analytical Method for Modeling Two-Phase Flow Behavior in Fractured Carbonate Oil Reservoirs

It is quite common for oil/gas two-phase flow in developing fractured carbonate oil reservoirs. Many analytical models proposed for black oil wells in fractured carbonate reservoirs are limited to single-phase flow cases and conventional methods have been the use of numerical simulations for this problem. In this approach, a novel semi-analytical method is proposed to integrate the complexities of phase change, pressure-dependent pressure-volume-temperature (PVT) properties, two-phase flow behavior, and stress-dependent fracture permeability characteristics. A dual-porosity, black oil model considering the phase change and two-phase flow is applied to model the fractured carbonate reservoirs. To linearize the model, only flow equations of oil phase are used to develop the mathematical model. Nonlinear parameters and producing gas–oil ratio (GOR) are updated with coupled flowing material balance equations, followed by a novel proposed procedure for history matching of field production data and making forecasts. The semi-analytical method is validated with a commercial simulator Eclipse. The results show that both of the production rate curves of oil and gas phase using the proposed model coincide with the numerical simulator. The results also show that the effects of pressure-dependent fracture permeability, fracture porosity, and exterior boundary on production rate are significant. Stress sensitivity influences production rate during the whole process, reducing the cumulative production. Fracture porosity influences production rate during the intermediate flow periods. The exterior boundary affects production rate mainly in the early and intermediate production periods. Finally, a field example from the eastern Pre-Caspian basin is used to demonstrate the practicability of the method. Acceptable history match is achieved and the interpreted parameters are all reasonable.

Investigation of the effects of low-salinity waterflooding for improved oil recovery in carbonate reservoir cores

ABSTRACTWater injection for both pressure maintenance and oil displacement is the most important secondary recovery method in sandstones. It has also been implemented with success in a few carbonate reservoirs, but because the most carbonate reservoirs worldwide are characterized as neutral to preferential oil-wet, normal waterflooding is usually not successful as an enhanced oil recovery (EOR) technique. It has been proved that seawater can be used as an EOR fluid for hot, fractured carbonate oil reservoirs since it is able to modify the wetting conditions and to enhance the oil recovery. The potential determining ions in seawater such as Ca2+, Mg2+, and SO42- played a crucial role in altering the wettability from oil-wet to more water-wet condition because of their reactivity towards the carbonate surface. In this paper, the potential of low-salinity brine to enhance the oil recovery has been studied. Four flooding tests were conducted on both limestone cores containing anhydrite and chalk core containing no sulfate. It is observed that low-salinity brine had only effect on rocks containing anhydrite. The dissolution of anhydrite, CaSO4, which is the source for SO42-, is depending on salinity/composition of brine and the temperature. The dissolution of anhydrite normally increases as the temperature decreases. Lowering the salinity of injection brine increases the reactivity of the surface-active ions SO42- and Ca2+.

Investigation of oil recovery and CO2 storage during secondary and tertiary injection of carbonated water in an Iranian carbonate oil reservoir

Abstract Gas injection process for more oil recovery and in particular CO 2 injection is well-established method to increment oil recovery from underground oil reservoirs. CO 2 sequestration which takes place during this enhanced oil recovery (EOR) method has positive impact on reducing the greenhouse gas emission which causes global warming. Direct gas injection into depleted oil reservoirs, encounters several shortcomings such as low volumetric sweep efficiency, early breakthrough (BT) and high risk of gas leakage in naturally fractured carbonate oil reservoirs. Carbonated water injection (CWI) has been recently proposed as an alternative method to alleviate the problems associated with gas injection. In this paper, the results of extensive experimental tests of ultimate oil recovery efficiency as both secondary and tertiary CWI tests and their CO 2 storage capacity for an Iranian carbonate reservoir are presented. Besides, the CWI recovery efficiencies are compared with traditional water flooding (WF) test. The results showed that higher ultimate oil recovery is achieved when carbonated water is injected as secondary technique compared to tertiary process. The results showed 40.54% and 56.74% more oil recovery during tertiary carbonated water injection (TCWI) and secondary water injection (SCWI) compared to the corresponding water flooding, respectively. However, the CO 2 storage capacities for both TCWI and SCWI cases were almost the same, as it was measured to be more than half of the total delivered CO 2 .

Enhanced oil recovery from high-temperature, high-salinity naturally fractured carbonate reservoirs by surfactant flood

Abstract Water floods are often very inefficient in naturally fractured carbonate oil reservoirs because many of these reservoirs are mixed-wet or oil-wet as well as extremely heterogeneous. Naturally fractured reservoirs are challenging targets for chemical flooding because they typically have a high permeability contrast between the fractures and the matrix with a low matrix permeability. Some of the world׳s largest oil reservoirs are fractured carbonates with a high reservoir temperature and a high salinity formation brine. Some of them also have low API gravity oils, which also increases the difficulty of recovering the oil. A surfactant formulation has been developed that shows promising results for such difficult reservoirs. Ultra-low interfacial tension (IFT) and good aqueous stability were achieved with this new carboxylate surfactant in a hard brine at a high reservoir temperature of 100 °C. Both static and dynamic imbibition experiments were conducted using a fractured carbonate core. 65.9% Oil recovery was obtained in fractured coreflood compared to 33.3% oil recovery in static imbibition test. The surfactant retention was low at 0.086 mg/g of rock. The oil recovery is excellent taking into account that the temperature and salinity conditions were harsh, the core was extremely vuggy and fractured, no mobility control was used, and only a small surfactant slug was injected. The coreflood results were interpreted using a mechanistic chemical reservoir simulator. It showed that both the mechanisms of IFT reduction and wettability alteration were important for oil recovery. Neither IFT reduction nor wettability alteration alone recovered oil as high as the combined contributions from both.

Acid Leakoff Mechanism in Acid Fracturing of Naturally Fractured Carbonate Oil Reservoirs

In acid fracturing, excessive acid leakoff is thought to be the main reason that limits fracture propagation and live acid penetration distance. Since most carbonates are naturally fractured, we developed a new model in this paper to simulate acid leakoff into a naturally fractured carbonate oil reservoir during acid fracturing. Our model incorporates the acid-rock reaction, fracture width variation due to rock dissolution on the fractured surfaces, and fluid flow in naturally fractured carbonate oil reservoirs. Given the information of the reservoir, injected acid, and pressure in the hydraulic facture and the reservoir, the model predicts acid leakoff with time. In this study, we found that acid leakoff mechanism in naturally fractured carbonates is much different from that in reservoirs without natural fractures. Widened natural fractures by acid-rock reaction act as high-conductivity conduits allowing leakoff acid to penetrate deeper into the formation, resulting in serious leakoff. Wide natural fractures have a dominant effect on acid leakoff compared to micro-fractures and matrix.

Naturally Fractured Carbonate Oil Reservoir: Reserve Estimation Study

A naturally fractured carbonate reservoir is chosen for implementing uncertainty assessment on estimation of original oil in place. The probability distribution of uncertain variables is defined in reserve estimation and evaluating probable reserve by using Monte Carlo simulation. The reserves are estimated for Karabogaz, Kbb-C member of Karababa and Derdere formations. The reserve estimation in fracture is based on available logs and tests about fracture parameters like density and width. The production data is used for verifying the calculated fracture porosity distributions. The mean of reserve distributions are close to deterministic ones. The sensitivity analysis on input parameters showed that matrix porosity, net thickness, and fracture porosity are significant in Karabogaz and Kbb-C formation reserve estimation while water saturation and fracture porosity are most significant in estimation of Derdere formation reserves.

The Effect of Asphalt Precipitation on Flow Behavior and Production of a Fractured Carbonate Oil Reservoir During Gas Injection

The first field data, collected over an 11 year period, are presented which indicate the possible effect of asphalt precipitation on the permeability and injectivity index of a fractured carbonate oil reservoir. The asphalt aggregates were formed during enhanced oil recovery by injection of a rich gas into the reservoir. The data indicate that, while at the initial stages of the operations the permeability and injectivity index decrease, at later times they appear to oscillate with the process time, with apparent oscillations' periods that depend on the heterogeneity of the reservoir. Two classes of plausible mechanisms that give rise to such oscillatory behavior are discussed. One relies on the changes in the structure of the reservoir's fractures, while the other one is based on asphalt precipitation in the reservoir. Computer simulations of flow and precipitation of asphalt aggregates in a pore network model of the reservoir are carried out. The results appear to support our proposition that asphalt formation and precipitation in the reservoir are the main mechanism for the observed behavior of the injectivity index. We also develop a stochastic continuum model that accurately predicts the time-dependence of the reservoir's permeability and injectivity index during the gas injection process.

Modelling the Performance of an Iranian Naturally Fractured Reservoir

Introduction An Iranian Asmari reservoir with an initial oil-in-place of about 381 million m3 (2.4 billion bbls) and a history of 18 years of oil production is studied in this: work. The field is a typical Iranian fractured carbonate oil reservoir which has a matrix rock of poor quality and a highly permeable fracture network. The subject of the study was to simulate the reservoir flow performance with an elaborate two-dimensional vertical model capable of simulating non-conventional producing mechanisms such as gravity drainage and block to block interaction. After successful proving of the model capability by reservoir production history, the model was used to predict the reservoir behaviour under natural depletion, and to evaluate two cases of pressure maintenance by gas injection. Results showed that in both cases of pressure maintenance, an ultimate additional oil production of about 150 million bbls will be achieved over natural depletion. This additional oil production corresponds to approximately 6% of original oil-in-place. Introduction The oil reservoir under study is an elongated NW-SE anticline symmetrical along its minor axis located in southwest of Iran. The structure plunge to the southeast is more gentle than to the northwest. The productive area is 19.5 kilometres long and 7.75 kilometres wide at the original WOC located at 1,890 metres subsea. Heavy mud losses during drilling, production tests, and good pressure communication between the wells indicate the existence of an active fracture system. The original reservoir pressure at a depth of 1,600 mss, was measured to be 210.7 bars, about 57 bars above saturation pressure. Commercial oil production commenced in 1973 at a rate of 3,100 m3/day. The rate was then successively increased as more wells were drilled in the field. During the early time of the field production, a relatively fast pressure drop as shown in Figure 1 was encountered which is characteristic of an undersaturated reservoir. In 1978, the pressure at the crest had dropped below the bubble point pressure causing the liberation of solution gas and the formation of a secondary gas cap. The field was shut-in from 1979 to 1984 during which 0.2 billion m3 of gas was injected intermittently. During this period the average reservoir pressure increased by approximately 20 bars. Then production resumed at a rate of 6,000-6,500 m3/D with a gas injection rate of 1.4 million m3/D continuously. From 1986 the amount of injected gas was insufficient to maintain the reservoir pressure, resulting in a gradual decline of the reservoir pressure. Figure 2 depicts the reservoir production history. The producing mechanisms in the fractured reservoirs of Iranian type are substantially different from those in conventional homogeneous reservoirs. Therefore, to study their performance a special mathematical model should be used. In this study it will be shown that the two-dimensional fractured reservoir model, a "stacked block model," which describes the reservoir as a series of stacked interacting blocks surrounded by fracture space, can be successfully applied to simulate the performance of the reservoir.