Carbonate Heavy Oil Reservoir Research Articles

In situ combustion performance in heavy oil carbonate reservoirs: A triple-porosity numerical model

This study aims to address the challenges of oil recovery in highly heterogeneous carbonate reservoirs by employing a novel triple-porosity numerical model approach for in-situ combustion (ISC). The primary focus is on the performance of ISC within isolated vuggy pore spaces, a characteristic feature of such reservoirs. By simulating triple-porosity through artificially induced vuggs, core matrix, and fractures, we evaluated the feasibility of the ISC technique for heavy oil recovery in a dolomite reservoir using a combustion tube setup.The numerical model, calibrated through history matching, incorporates an extended kinetic reaction scheme to better represent high-temperature oxidation processes. Experimental and simulation results show a strong correlation in temperature profiles, ignition timing, and fluid production, effectively reproducing the observed gas compositions. This integrated experimental and numerical approach demonstrates the potential for applying ISC in triple-porosity systems, offering valuable insights for field-scale implementations in similarly complex carbonate reservoirs. The novelty of this research lies in its comprehensive modeling of the first ISC experiment in a triple-porosity framework, providing a deeper understanding of the interactions between matrix, fracture, and vugg networks, and paving the way for enhanced oil recovery (EOR) strategies in challenging reservoir environments.

Exploring in-situ combustion effects on reservoir properties of heavy oil carbonate reservoir

Laboratory modeling of in-situ combustion is crucial for understanding the potential success of field trials in thermal enhanced oil recovery (EOR) and is a vital precursor to scaling the technology for field applications. The high combustion temperatures, reaching up to 480 °C, induce significant petrophysical alterations of the rock, an often overlooked aspect in thermal EOR projects. Quantifying these changes is essential for potentially repurposing thermally treated, depleted reservoirs for CO2 storage.In this study, we depart from conventional combustion experiments that use crushed core, opting instead to analyze the thermal effects on reservoir properties of carbonate rocks using consolidated samples. This technique maintains the intrinsic porosity and permeability, revealing combustion's impact on porosity and mineralogical alterations, with a comparative analysis of these properties pre- and post-combustion. We characterize porosity and pore geometry evolution using low-field nuclear magnetic resonance, X-ray micro-computed tomography, and low-temperature nitrogen adsorption. Mineral composition of the rock and grain-pore scale alterations are analyzed by scanning electron microscopy and X-ray diffraction.The analysis shows a significant increase in carbonate rocks’ porosity, pore size and mineral alterations, and a transition from mixed-wet to a strongly water-wet state. Total porosity of rock samples increased in average for 15%–20%, and formation of new pores is registered at the scale of 1–30 μm size. High-temperature exposure results in the calcite and dolomite decomposition, calcite dissolution and formation of new minerals—anhydrite and fluorite. Increased microporosity and the shift to strongly water-wet rock state improve the prospects for capillary and residual CO2 trapping with greater capacity. Consequently, these findings highlight the importance of laboratory in-situ combustion modeling on consolidated rock over tests that use crushed core, and indicate that depleted combustion stimulated reservoirs may prove to be viable candidates for CO2 storage.

Reservoir Properties Alteration in Carbonate Rocks after In-Situ Combustion

Summary This study summarizes the work conducted as a part of laboratory modeling of in-situ combustion (ISC) experiments on cores from carbonate heavy oil fields. Porosity, permeability, fluid saturation, thermal, and geochemical properties are crucial characteristics of the target field defining the performance of the combustion technology. Here, we report the changes in reservoir properties, porous structure, and mineral composition of the rock samples induced by the thermal exposure and registered by a set of standard and advanced experimental techniques. Most combustion tests are conducted on the crushed core pack, which does not accurately represent the reservoir properties. In this paper, we present the results of three combustion tube tests (classic ISC and consecutive hot-water treatment ISC) involving actual field core samples. Gas porosimetry, nuclear magnetic resonance (NMR), and microcomputed tomography (μCT) revealed an increase in total porosity and pore size distribution and enabled visualizing the changes in the porous core structure at nano- and microlevels. X-ray diffraction (XRD) and scanning electron microscopy (SEM) demonstrated the change in mineral composition and lithological texture as a result of dolomite decomposition; Rock-Eval pyrolysis and elemental analysis were utilized to confirm the changes in the rock matrix. Optical scanning registered the changes in thermal conductivity (TC) of samples, which is important for numerical modeling of the combustion process. The proposed core analysis has proved its efficiency in providing a complete petrophysical description of the core of a heavy oil carbonate reservoir in the framework of evaluation of the ISC application for dolomite-rich carbonates and demonstrated the different responses of rock to the ISC technology.

Comparative Study of In-Situ Combustion Tests on Consolidated and Crushed Cores

Summary A significant amount of oil is contained in carbonate reservoirs, but only half of that oil can be produced by secondary enhanced oil recovery (EOR) methods. However, substantial improvements were made in EOR techniques and the prediction of carbonate reservoir performance within the last decades. Nevertheless, existing flow-simulation computer programs failed to provide a reliable prediction of such reservoirs due to their high heterogeneity and the reactivity of the rock. Potentially, in-situ combustion (ISC) is considered effective in developing heavy oils in carbonate reservoirs. The combustion reactions between crude oil and heterogeneous rock matrices introduce additional complexity to the simulation process. Also, most of the laboratory experiments studying the reaction kinetics of the ISC process are performed on the crushed core. However, to minimize the risks, improve the control of the process, and overcome upscaling issues, physical simulation must be carried out under conditions as close to the reservoir as possible. Consolidated core material in combustion tube (CT) experiments is desirable for better simulating some reservoir conditions with synthetic packs and for the cases when actual preserved reservoir core material may be available. Studying the relative effects of porosity and packing properties (specific surface area, sand grain distribution, and cementation) on the fuel is essential to evaluating the process under actual field conditions. This work presents a set of medium-pressure CT (MPCT) tests on crushed and consolidated cores and analyzes the differences, limitations, and performances of both approaches. Two MPCT tests were performed to evaluate the ISC feasibility on the heavy-oil carbonate reservoir with an initial oil saturation level of 0.38 to 0.50. According to previously published experimental results, such oil saturation levels can help avoid oil banking. Both experiments were conducted at reservoir conditions to consider the phase behavior at elevated pressures and temperatures. The method used in this research allows approbation of the methodology of ISC tests using consolidated core at high pressure, ensuring pack and process integrity during the experiment. The influence of consolidated core caused by significantly lower porosity and more uniform porous media elements than those made with unconsolidated material on combustion performance was assessed. Valuable data for different variations of combustion experiments were generated. This work compared two tests and presented the combustion parameters for a stabilized combustion period, such as fuel and air requirements, recovery efficiency, front velocity, and composition of produced gases. The research intends to demonstrate the potential application problems and address issues that might arise during ISC application on target reservoirs, including the higher air flux required for lower porosity of consolidated core samples. The experimental results performed under conditions closest to reservoir conditions are essential for further predictions and affect the ISC performance during pilot tests.

CO2-saturated brine injection into heavy oil carbonate reservoirs: Investigation of enhanced oil recovery and carbon storage

Fossil fuel to a large extent is still expected to dominate the global energy demands for the next few decades. An inevitable and detrimental consequence of such source of energy is though the emission of hazardous CO2. Therefore, technologies that can utilize and permanently store the emitted CO2 are of great interest for the energy industry. A viable large-scale CO2 utilization and storage technology is the CO2 enhanced oil recovery (EOR) technique. However, this technique mostly lacks a good volumetric sweep efficiency at the reservoir-scale. An alternative option is CO2-saturated (carbonated) water injection (CWI). Although the oil recovery and CO2 storage potential of CWI for light and medium crude oil systems have been extensively studied, only a few studies investigated carbon storage particularly in heavy oil reservoirs. As such, this study through an experimental approach provides more insights into this subject. The results show that the high asphaltene contents of the used heavy crude oil led to formation of in-situ water-in-oil emulsions during both waterflooding and CWI. Emulsions decreased the flow path area of injection fluid and blocked some pores and throats, which consequently led to local flow diversions to un-swept areas of the porous media and an improvement in oil recovery. The emulsion-induced local flow diversions during CWI improved the effectiveness of oil recovery mechanisms of CWI by bringing more residual oil in contact with carbonated brine. Both secondary and tertiary CWI led to 24% and 20% higher oil recovery compared to conventional waterflooding, respectively. Furthermore, during secondary and tertiary CWI around 22% and 32% of the total injected CO2 were stored in the core plugs mostly by solubility trapping in the residual oil. The CO2 utilization factor increased over the carbonated brine injection period indicating higher CO2 needs to be injected for producing a barrel of oil.

Improved reservoir characterization by employing hydraulic flow unit classification in one of Iranian carbonate reservoirs

Capillary pressure curves is of great importance in reservoir characterization. Due to the reservoir heterogeneity, no single capillary pressure curve can be used for the entire reservoir depth. This paper aims to examine the application of different techniques of hydraulic flow unit (HFU) classifications in overcoming the extreme heterogeneity of the reservoir in order to improve normalization of capillary pressure in one of the Iranian carbonate oil reservoirs. In this study, well log, routine and specific core analysis lab data have been used to identify flow units by employing different techniques in a heavy oil carbonate reservoir in the south of Iran. These techniques include gamma ray and density log method, flow zone indicator, capillary pressure curves and Winland parameter. Then, mercury injection data has been used by employing Desouky's method to normalize capillary pressure curves for each identified flow unit. According to this study HFU classification significantly improved normalizing of capillary pressure curves. Cited as : Rafiei, Y., Motie, M. Improved reservoir characterization by employing hydraulic flow unit classifification in one of Iranian carbonate reservoirs. Advances in Geo-Energy Research, 2019, 3(3): 277-286, doi: 10.26804/ager.2019.03.06

Significant effect of compositional grading on SAGD performance in a fractured carbonate heavy oil reservoir

In reservoir simulation, the fluid composition is usually assumed uniform for the whole reservoir, while in many reservoirs, oil and gas composition changes with depth. This phenomenon which is known as compositional grading could be significant in heavy and super heavy oil reservoirs. In these reservoirs, biodegradation and asphaltene precipitation are considered as the main reasons behind this phenomenon. Compositional grading in heavy oil reservoirs could affect fluid viscosity and vaporizing–condensing mechanism in steam-assisted gravity drainage (SAGD) operations. In this paper, through a simulation study, one of the Iranian heavy oil reservoirs which have a significant compositional grading was selected to investigate the effect of compositional grading on the performance of simulated SAGD method. The reservoir is a fractured carbonate reservoir, and its compositional grading is maintained because of the lack of convection inside the reservoir. To verify the importance of compositional grading, the performance results of the SAGD method for compositional grading case were compared with that of uniform composition case. The result showed that ignoring compositional grading would lead to underestimation of ultimate recovery in the fractured model. The study of SAGD process in a non-fractured reservoir model showed that considering compositional grading has an insignificant effect on SAGD performance.

Measurement of Damköhler number on the X-Ray computed tomography basis in the process of heavy oil carbonate reservoir acidizing

Nowadays, cases of the joint use of thermal and chemical methods of enhanced oil recovery have become more frequent. In this regard, acid treatment has an important role, which allows increasing the productivity of wells with low-permeability carbonate reservoirs. At the experimental level, the presence of an optimal injection mode has been proven, that depends on the dimensionless of Damköhler number and leads to the formation of “wormholes” of dissolution with increasing reservoir permeability. In this work, a new optimized method for calculating the Damköhler number based on X-ray computed tomography data is proposed. A comparison of the calculation of values by the classical and the new technique for different wormholes is presented.

Phased Pilot Approach Reduces Uncertainty in Carbonate Steamflood Development

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191695, “Results From a Phased Piloting Approach in the First Eocene Reservoir of Wafra: Reducing Uncertainties in Carbonate Steamflood Development,” by David Barge, SPE, Joel Brown, Raushan Kumar, Chris Lolley, SPE, Ruurd Bartlema, and Saleh Al-Ghamdi, Chevron, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. The First Eocene is a multibillion-barrel heavy-oil carbonate reservoir in the Wafra field, located in the Partitioned Zone (PZ) between Saudi Arabia and Kuwait. After more than 60 years of primary production, expected recovery is low and provides a good target for enhanced-oil-recovery (EOR) processes. A phased piloting approach has been used to reduce the uncertainties (subsurface and surface) related to application of thermal EOR processes in this field. Introduction Wafra is one of four major fields located in the PZ (Fig. 1). Because of the low primary oil recovery and large original oil in place of the Wafra Eocene reservoirs, a significant EOR opportunity exists. A detailed geological description of the reservoir is provided in the complete paper. Because of key surface and sub-surface uncertainties, along with the high cost of implementing a full-field steamflood-development (FFSFD) project, a phased, sequential approach, from piloting to FFSFD, was implemented. This approach was required so that critical uncertainties could be evaluated efficiently and sequentially in a time-frame consistent with overall reservoir- development objectives while managing capital exposure. Pilot Planning and Design Steamflood Pilots. A specific set of objectives, primary and secondary, was developed for each of the continuous-steam-injection (CSI) pilots. Primary objectives were identified as being critical for progression to the next phase (piloting/FFSFD); secondary objectives were regarded as important in understanding identified uncertainties, but not necessarily project roadblocks. Success measures for the pilots were derived from the key metrics that were prerequisites for the next phase. These success measures were formulated to ensure that learnings gained will be used to support the design and operational planning of the next phase. A five-spot pattern on a 1.25-acre steamflood-pilot, small-scale test (SST) was a continuation of the phased approach in managing and mitigating technical uncertainties related to implementing steamflooding. The primary objectives of the SST were to test whether Eocene-produced water could be treated to produce suitable feedwater for steam generation and to test steam injectivity in the First Eocene reservoir. The SST was conducted in First Eocene C Zone/Steam Zone 3 and successfully proved sustained injectivity using steam generated from the produced water. The SST was a pre-lude to a multipattern steamflood pilot known as the large-scale pilot (LSP).

A preliminary feasibility analysis of in situ combustion in a deep fractured-cave carbonate heavy oil reservoir

As an effective thermal-enhanced oil recovery technique, in-situ combustion (ISC) can achieve large oil displacement efficiency and upgrade the heavy oil technically, but there are still various barriers for ISC application in naturally fractured carbonate heavy reservoirs. In addition, the potential risk of wellbore plugging and formation collapse, caused by the possibility of carbonate rock decomposition at high temperatures, furtherly hinders the application of ISC technique and focuses more attention on feasibility evaluation. Hence, this paper attempted to estimate the preliminary feasible application of ISC in Tahe oilfield, characterized with fractured-cave carbonate heavy reservoir. From macro and micro aspects, results indicated that owing to large microscopic surface area and high oxygen contact ability between the deposited coke and oxygen, the oxidized ultra-heavy oil, under adiabatic condition, in simulative fractured-cave carbonate oil reservoir was successfully ignited and maintained the combustion process with the combustion front temperature. Besides, a large amount of heat generation from the combustion front can activate the ultra-heavy oil with better mobility ability. Additionally, in this process, the decomposition process of Tahe carbonate rock was not triggered (∼631.6 °C) where the decomposition risk of running in-situ combustion process in Tahe carbonate reservoir can be neglected. Preliminarily, it implied that ISC is a feasible technique to upgrade the ultra-heavy oil for Tahe oilfield.

Origin of oil geochemical compositional heterogeneity in the Radhuma and Tayarat formations heavy oil carbonate reservoirs of Burgan Field, south Kuwait

This is a qualitative assessment study to understand origin controlling lateral/geographic and vertical/stratigrahic heterogeneity of Radhuma (Palaeocene) and Tayarat (Maastrichian) Formation heavy oil reservoirs in the Burgan Field in south Kuwait. Data from oil analyses, including physical properties, bulk chemical composition, sulphur content, molecular chemical composition, and carbon and sulphur isotopes, were used to characterise the different oils in the reservoirs. Geochemical fingerprinting and characterisation suggest that the key impact on compositional heterogeneity has been the mixing of some petroleum—by the addition of lighter oil to extra-heavy oil. Therefore, the proposed complex filling history model for the Radhuma and Tayarat reservoirs consists of six episodes: two oil entrapments and four thermochemical sulphate reduction (TSR) fluid pulses. Finally, it is postulated that lighter fresh charge oils in the Burgan Field were sourced upward from deeper reservoirs associated with the reactivation of deep-seated faults as a result of structural compression events during Upper Cretaceous and Neogene time.

Feasibility study on application of the recent enhanced heavy oil recovery methods (VAPEX, SAGD, CAGD and THAI) in an Iranian heavy oil reservoir

ABSTRACTEnhanced oil recovery (EOR) methods assisted by gravity drainage mechanism and application of sophisticated horizontal wells bring new hope for heavy oil extraction. Variety of thermal and non-thermal EOR techniques inject an external source of energy and materials such as steam, solvent vapor, or gas through a horizontal well at the top of the reservoir to reduce in-situ heavy oil viscosity. So, the diluted oil becomes mobile and flows downwards by gravity drainage to a horizontal producer located at the bottom of the reservoir.In this paper, a sector model of an Iranian fractured carbonate heavy oil reservoir was provided to simulate and evaluate capability of some EOR techniques such as Vapor Extraction (VAPEX), Steam Assisted Gravity Drainage (SAGD), Combustion Assisted Gravity Drainage (CAGD), and Toe to Heel Air Injection (THAI) at its reservoir conditions and fluid properties. The simulation results demonstrated that wet CAGD in comparison with other nominated methods could improve heavy oil recovery factor to around 19% much more than each of SAGD, THAI, and VAPEX techniques. It could also reduce the total energy to produced oil ratio index up to 82% with respect to SAGD process in a year.Although lower oil recovery has been gained by VAPEX process, but using a proper vaporized solvent could produce a kind of de-asphalted and upgraded oil with increased API gravity up to 29°API with no considerable solvent loss.

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.

Quantitative Viscosity, Movable Oil, and Texture Evaluation in a Heavy-Oil Carbonate Reservoir With Advanced Dielectric and Nuclear-Magnetic-Resonance Log Integration

Summary Textural and wettability variations are two main vexing problems in carbonate reservoirs. Adding heavy oil presents an incremental challenge to the reservoir description. Ineffectual analysis often leads to poor completion and high water production. Integrating multifrequency-dielectric and nuclear-magnetic-resonance (NMR) logs leads to improved carbonate-reservoir evaluation. Dielectric and NMR logs have similar depths of investigation, both probing the flushed zone. It is difficult to distinguish bound water from heavy oil in rocks from NMR tools alone. The addition of accurate water-filled-porosity (ϕW) measurements from the dielectric log allows us to differentiate the fluids. Using ϕW as a reference and accounting for restricted molecular diffusion in small pores, NMR analysis on the basis of diffusion relaxation provides more-accurate oil viscosity and fluid volumes. The computation of viscosity from NMR assumes that the oil relaxation is dominated by bulk relaxation; oil-wetting of pore surfaces causes viscosity to be overestimated. Conversely, the wetting state can be inferred if the viscosity is known. Dielectric dispersion with frequency provides a measure of the water-phase tortuosity MN_De, which in turn is affected by texture and wettability. We compared the in-situ NMR signal of oil to the surface NMR measurement of a bulk-oil sample. We also identified a correlation between MN_De and the Archie cementation exponent, mainly driven from NMR. This leads to interesting conclusions about texture and wettability, which are found to be coherent with the existing reservoir data. Together with the viscosity profile, the comparison between the pore-fluid volumes in the flushed zone and the bulk volume of water from deep resistivity is used to identify the zones of movable oil and to estimate residual oil saturation. The method was applied to data sets from three wells in a shallow carbonate reservoir. The estimated viscosity was validated by pressure/volume/temperature (PVT) analysis. In two wells, the prediction of movable oil and water zones was confirmed by downhole test results. In the third well, the free-water zone was confirmed by production logging.

Utilisation of multiple gas injection to enhance oil recovery for fractured-cavity carbonate heavy oil reservoir

Gas injection has been proven to be a valuable enhanced oil recovery (EOR) process for light oil reservoirs and ordinary heavy oil reservoirs, but it was rarely proposed as an EOR process for fractured-cavity carbonate heavy oil reservoir. This study aims to investigate the feasibility of the gas injection based on flooding and cycle stimulation method with respect to enhancing oil recovery for fractured-cavity carbonate heavy oil reservoir. Thus, a representative physical model of core was designed, and some gas flooding and cyclic gas stimulation experiments were conducted. The experimental results show that gas injection can enhance the oil recovery in fractured-cavity carbonate reservoir and carbon dioxide is the optimal injected gas in this study. Also, gravity drainage plays an important role in fractured-cavity carbonate reservoir besides the various recovering mechanisms in conventional reservoir. In addition, Tahe heavy oil has a strong capacity of oxygen consumption due to the high content of polar compound. [Received: May, 1, 2015; Accepted: February 29, 2016]

Utilisation of multiple gas injection to enhance oil recovery for fractured-cavity carbonate heavy oil reservoir

Gas injection has been proven to be a valuable enhanced oil recovery (EOR) process for light oil reservoirs and ordinary heavy oil reservoirs, but it was rarely proposed as an EOR process for fractured-cavity carbonate heavy oil reservoir. This study aims to investigate the feasibility of the gas injection based on flooding and cycle stimulation method with respect to enhancing oil recovery for fractured-cavity carbonate heavy oil reservoir. Thus, a representative physical model of core was designed, and some gas flooding and cyclic gas stimulation experiments were conducted. The experimental results show that gas injection can enhance the oil recovery in fractured-cavity carbonate reservoir and carbon dioxide is the optimal injected gas in this study. Also, gravity drainage plays an important role in fractured-cavity carbonate reservoir besides the various recovering mechanisms in conventional reservoir. In addition, Tahe heavy oil has a strong capacity of oxygen consumption due to the high content of polar compound. [Received: May, 1, 2015; Accepted: February 29, 2016]

Corrigendum to “Theoretical and experimental insights on the true impact of C12TAC cationic surfactant in enhanced oil recovery for heavy oil carbonate reservoirs” [Colloids Surf. A: Physicochem. Eng. Aspects 455 (2014) 76–91

Corrigendum to “Theoretical and experimental insights on the true impact of C12TAC cationic surfactant in enhanced oil recovery for heavy oil carbonate reservoirs” [Colloids Surf. A: Physicochem. Eng. Aspects 455 (2014) 76–91

Thermo-EOR effect during steam injection in carbonate heavy oil reservoirs

When the thermal method is applied to carbonate rock, the imbibitional flow into tight matrix can be increased by thermally induced wettability alteration. Furthermore, CO2 is generated by geochemical reaction between steam and carbonate rock, resulting in thermo-EOR, which is similar to CO2 flooding. In this study, we developed geochemical model to predict the generation of CO2 and implemented this model into a thermal simulator. Using this thermal model, we investigated thermo-EOR effect by the generated CO2 in heavy oil carbonate reservoirs and analysed the capillary imbibition resulting from the wettability alteration. From the results, we determined that thermo-EOR effect from the generated CO2 only occurred under the influence of immiscible flow, which yielded additional 12.5% of oil recovery. This gain was obtained from additional decrease in oil viscosity by the dissolved CO2 in oil and further increase in pore pressure due to the volume of the CO2 gas. [Received: September 10, 2014; Accepted: January 19, 2015]

Theoretical and experimental insights on the true impact of C12TAC cationic surfactant in enhanced oil recovery for heavy oil carbonate reservoirs

Herein were performed theoretical and experimental studies about the performance of the cationic surfactant docecyltrimethylammonium chloride (C12TAC) on the enhancement of the oil recovery factor (ORF) from heavy oil-impregnated calcite cores. The interaction energies between C12TAC and either of some molecules present in oil such as an asphaltene (Asph), a resin (Res) or an octanoic acid, and among these and a calcite surface were theoretically determined within the framework of the Density Functional Theory. Experimental analysis based on Fourier transform infrared (FTIR) spectroscopy as well as 1H and 13C nuclear magnetic resonance (NMR) spectra were made on the heavy crude oil recovered by spontaneous imbibition tests from the calcite cores. Results evidenced that, by using brine containing 2.9ppm×105ppm of total ion, it were obtained ORF values of 8.9% at 90°C temperature and atmospheric pressure, and 36% at 150°C temperature and 145psi pressure. Meanwhile with the inclusion of C12TAC at the same temperature and pressure conditions used in pure brine experiments, noticeable increased ORF values of 36% and 44%, respectively, were found. From the molecular interaction strengths between C12TAC and the fractions present in the oil, it has been evidenced also the oil disaggregation as well as the subsequent oil viscosity reduction, but finally without significant wettability alteration of the calcite core. A saturated, aromatics, resins and asphaltenes (SARA) component analysis revealed a significant change in composition moving from their original values of 20.6, 21.0, 35.5 and 22.9%, respectively, to 31.0, 23.2, 28.7 and 17.2%, accordingly. The lack of wettability alteration of C12TAC in such process is due to a weak interaction in C12TAC:Res and C12TAC:Asph molecular pairs followed by a clear diminishment of Res and Asph fractions in SARA, which reveals Asph and Res cannot be removed from rock surface. The quantum nature of the supramolecular assembling between the cationic surfactant and oil molecules is described by molecular orbitals analysis.

Tests Investigate Recovery Mechanisms of Steam Injection in Carbonate Reservoir

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 153812, ’Investigation of Recovery Mechanism of Steam Injection in Heavy-Oil Carbonate Reservoir and Mineral Dissolution,’ by Guo-Qing Tang, SPE, Art Inouye, Vincent Lee, SPE, Dustin Lowry, and Wei Wei, Chevron, prepared for the 2012 SPE Western Regional Meeting, Bakersfield, California, 19-23 March. The paper has not been peer reviewed. Steam injection in carbonate heavy-oil reservoirs is a complex process. The main challenge is that the injected steam breaks through from a fracture network, resulting in poor sweep efficiency. A large amount of oil remains behind the steam front. In addition, severe mineral dissolution (or precipitation) because of steam/brine/rock interaction at high temperatures has a significant effect on steam injectivity and recovery mechanisms. An extensive laboratory study focused on understanding the recovery mechanism and relevant mineral dissolution. Introduction Ten reservoir cores and 14°API crude oil were used for this study. Imbibition, steamflooding, and pressure blowdown tests were conducted. The results show that the recovery mechanism of steam injection in the target carbonate reservoir is composed of imbibition, viscosity reduction, in-situ steam generation induced by pressure blowdown, and oil expansion mechanisms. As the rock is heated to near 400°F, imbibition becomes the dominant recovery mechanism. The increased imbibition recovery is strongly dependent on mineral dissolution at a high temperature, which results in wettability alteration to-ward strong water-wetness. Because of microfractures, steamdrive is less efficient compared with imbibition. In-situ steam generation still can increase oil recovery by an additional 17–32% of original oil in place (OOIP) following steamflood displacement at residual oil saturation. Significant mineral dissolution is observed with high-resolution computed tomography (CT) scanning and effluent geochemical analysis. CT-image analysis shows that the size of vugs is increased 2 to 5 times by mineral dissolution. Mineral dissolution does not increase the effective permeability because these vugs are mainly connected by microfractures, where mineral dissolution effects are negligible. In fact, permeability is reduced by fines migration resulting from mineral dissolution. Experiments Carbonate reservoir rock samples with permeability ranging from 121 to 317 md and porosity ranging from 40.1 to 50.9% were selected for this study. CT scans showed that the selected rock samples have many vugs, with a size ranging from 0.11 to 3 mm. These vugs are connected with very tiny pores and microfractures with sizes of approximately 20 µm. An in-house high-temperature (up to 400°F) and -pressure (up to 1,000 psi) experimental system that is capable of running either free imbibition (counter-current) or forced imbibition (cocurrent) was used for all experiments. Different experiments, such as free imbibition, forced imbibition, thermal expansion, steamflooding, and pressure blowdown, were performed. Fig. 1 shows the experimental design.