Se, Yegor (Chevron Energy Technology Company) | Villegas, Mauricio (Chevron) | Iskakov, Elrad (Chevron) | Playton, Ted (Tengizchevroil) | Lindsell, Karl (Tengizchevroil) | Cordova, Ernesto (Chevron Energy Technology Company) | Turmanbekova, Aizhan | Wang, Haijing
Secondary oil recovery projects in naturally fractured carbonate reservoirs (NFR) often introduce uncertainties and challenges that are not common to conventional waterfloods. The recovery mechanism in NFRs relies on ability of the fracture network to deliver enough injected fluid to the matrix, as well as rate and magnitude of capillary interactions within the matrix rock, during which hydrocarbon displacement occurs. The imbibition measurements can be performed in the laboratory using core samples, but due to reservoir heterogeneity, certain limitations of the lab equipment and the quality of the core material, scalability of the core results to a reservoir model can be challenging.
This paper describes the design, execution and evaluation of the’ log-soak-log’ (LSL) pilot test conducted in a giant naturally fractured carbonate reservoir with a low-permeability matrix in Western Kazakhstan, where repeatable and reliable measurements of changes in water saturation were achieved across large intervals (tens of meters) using a time-lapse pulsed-neutron logging technique. Periodic measurements provided valuable observations of dynamic change in saturation and fluid level over time and allowed estimation of the rate and magnitude of imbibition in the slope margins, depositional settings and rock types of interest. Incorporation of the LSL results into reservoir models validated the ranges of water-oil relative permeability curves, residual oil saturation to water, irreducible water saturation, and capillary pressure assumptions. This validation constrained key subsurface uncertainty and updated the oil recovery forecast in several improved oil recovery (IOR) waterflood projects.
Application of horizontal wells and multi-stage fracturing has enabled oil recovery from extremely low permeability shale oil reservoirs, but the decline in production rate is more than two thirds in the first two years. We are trying to develop chemicals that can be injected into old wells to stimulate oil production before putting the well back in production. The goal of this work is to evaluate chemical blends for such a process at the laboratory scale. The chemical blend contains surfactants, a weak acid, a potential determining ion, and a solvent. Six different solvents were screened: Cyclohexane, D-Limonene, Dodecane, Kerosene, Turpentine, and Green Solvent®. Most of the chemical blends with the solvents extracted about 60% of the oil from shale chips, but the Green Solvent® extracted about 84%. Spontaneous imbibition tests were performed with outcrop Mancos shale cores. Oil was injected into these outcrop cores at a high pressure. NMR T2 distributions were measured for the cores in the original dry state, after oil injection and after imbibition. The aqueous phase from the chemical blend imbibed into the cores and pushed out a part of the oil and gas present in the cores. The surfactant in these blends can change wettability and interfacial tension. The solvent can mix with the oil and solubilize organic solid residues such as asphaltenes. The weak acid can dissolve a part of the carbonate minerals and improve permeability. The synergy can make these chemical blends strong candidates to stimulate oil recovery in shale formations.
Lara Orozco, Ricardo A. (The University of Texas at Austin) | Abeykoon, Gayan A. (The University of Texas at Austin) | Wang, Mingyuan (The University of Texas at Austin) | Argüelles Vivas, Francisco J. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin) | Lake, Larry W. (The University of Texas at Austin) | Ayirala, Subhash C. (Saudi Aramco) | AlSofi, Abdulkareem M. (Saudi Aramco)
Reservoir wettability plays an important role in waterflooding especially in fractured carbonate reservoirs since oil recovery from the rock matrix is inefficient because of their mixed wettability. This paper presents the first investigation of amino acids as wettability modifiers that increase waterflooding oil recovery in carbonate reservoirs.
All experiments used a heavy-oil sample taken from a carbonate reservoir. Two amino acids were tested, glycine and β-alanine. Contact angle experiments with oil-aged calcite were performed at room temperature with deionized water, and then at 368 K with three saline solutions: 243,571-mg/L salinity formation brine (FB), 68,975-mg/L salinity injection brine 1 (IB1), and 6,898-mg/L salinity injection brine 2 (IB2). IB2 was made by dilution of IB1.
The contact angle experiment with 5-wt% glycine solution in FB (FB-Gly5) resulted in an average contact angle of 50°, in comparison to 130° with FB, at 368 K. Some of the oil droplets were completely detached from the calcite surface within a few days. In contrast, the β-alanine solutions were not effective in wettability alteration of oil-aged calcite with the brines tested at 368 K.
Glycine was further studied in spontaneous and forced imbibition experiments with oil-aged Indiana limestone cores at 368 K using IB2 and three solutions of 5 wt% glycine in FB, IB1, and IB2 (FB-Gly5, IB1-Gly5, and IB2-Gly5). The oil recovery factors from the imbibition experiments gave the Amott index to water as follows: 0.65 for FB-Gly5, 0.59 for IB1-Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This indicates a clear, positive impact of glycine on wettability alteration of the Indiana limestone cores tested.
Two possible mechanisms were explained for glycine to enhance the spontaneous imbibition in oil-wet carbonate rocks. One mechanism is that the glycine solution weakens the interaction between polar oil components and positively-charged rock surfaces when the solution pH is between glycine's isoelectric point (pI) and the surface's point of zero charge (pzc). The other mechanism is that the addition of glycine tends to decrease the solution pH slightly, which in turn changes the carbonate wettability in brines to a less oil-wet state.
The amino acids tested in this research are non-toxic and commercially available at relatively low cost. The results suggest a new method of enhancing waterflooding, for which the novel mechanism of wettability alteration involves the interplay between amino acid pI, solution's pH, and rock's pzc.
Surfactant-Assisted Spontaneous Imbibition (SASI) and gas injection have been proven to improve production from Unconventional Liquid Reservoirs (ULR). However, the novelty of the method has resulted in a few publications to date. This study utilizes numerical modeling to upscale laboratory data of SASI for completion purposes and gas injection plus SASI for EOR. Novel gas and aqueous-phase injection strategies following primary depletion are designed based on actual completion and production data. Multiple sequencing configurations for both surfactant and gas injection are tested to propose the best combined-EOR scheme for ULR.
Parameters related to the mechanism of SASI and gas injection are retrieved from CT-generated core-scale model of laboratory experiments. SASI and gas injection experimental results were upscaled to model production response of a hydraulically fractured well with realistic fracture geometry and conductivity. The core-scale model was created to determine the diffusion coefficient, relative permeability, and capillary pressure curves by history-matching the laboratory data. The field-scale model was developed with a dual-porosity compositional model to predict production enhancement for various combined-EOR schemes in ULR.
Wettability and IFT alteration are the two primary mechanisms for SASI in enhancing production. Experimental studies revealed that surfactant solution recovered up to 30% OOIP, whereas water alone only recovered approximately 10% OOIP. Capillary pressure and relative permeability constructed from scaling group analysis and core-scale numerical models showed that surfactant addition enhances the two curves. On the other hand, gas injection EOR was found to be driven by multi-contact miscibility and diffusion. Parameters related to both methods were applied to the field-scale model for multiple completion and EOR schemes. Results demonstrate that the combination of SASI and gas injection possesses significant potential in improving production rates and estimated ultimate recoveries (EUR) in ULR. Soak times, surfactant concentration, injection pressure, duration of the cycle, and cumulative gas injection control the level of enhancement. With a large number of control variables, specific customizations can be optimized to suit criteria of different field applications.
Successful implementation of a recovery project in a fractured reservoir requires that the matrix fracture mass transfer is well understood. As a consequence, several processes involved in the mass transfer have been widely studied along time on account of its impact on the fractured porous media. Capillary imbibition is one of these significant phenomena and is considered through wettability in several mass transfer formulations (also called transfer functions) as the main mass driving force between matrix and fracture. This paper presents simulated results of waterflooding tests in a fractured core-plug model, evaluating the influence of wettability and flow rate alteration on the matrix-fracture mass transfer. The methodology applied is divided into three main parts. Initially, a single-porosity core model with an induced longitudinally fracture at laboratory scale is recreated. Secondly, three synthetically wettability scenarios (water-wet, intermediate-wet, and oil-wet) and two flow rates (0.1 and 1 cm³/min) are selected and applied in the core-plug model to perform, as a third step, a sensitivity analysis in terms of oil recovery factor, water cut and water saturation. Results show that the increase of rock preference for water leads to the highest oil recovery factors at low and high-water injection rate, benefiting mainly from the spontaneous imbibition of water. The spontaneous imbibition in these cases is notably critical in the low-rate scenario, due to its larger contact time with water and rock. However, the increment on production may not be economically feasible, because of the long time (high injected pore volumes) needed to get this increase. In contrast, intermediate and oil-wet scenarios exhibit low oil sweep and displacement efficiency at both water injection rates. Accordingly, these scenarios reach water breakthrough quickly and exhibit a less accentuated tendency to water saturation alterations if compared with the water-wet scenario. Results also show a good agreement between the water saturation distributions along the length and the effect of the induced fracture, validating its use.
In a numerical simulation study, this work shows the importance of close interaction between the wettability, flow rate changes, and the parameters that control matrix-fracture mass transfer. At last, the significance of these sensitive parameters is also demonstrated.
Wang, Mingyuan (The University of Texas at Austin) | Baek, Kwang Hoon (The University of Texas at Austin) | Abeykoon, Gayan A. (The University of Texas at Austin) | Argüelles-Vivas, Francisco J. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin)
Tight oil reservoirs typically show rapid reduction in production rate within a few years. Various methods of improved oil recovery from tight reservoirs have been studied, such as cyclic injection of gas and chemical solutions. Chemical solution injection is expected to improve oil recovery through wettability alteration and water/oil interfacial tension (IFT) reduction because most tight oil reservoirs are reportedly intermediate- to oil-wet.
This paper presents a comparative study of two wettability modifiers with different characters for enhancing water imbibition from a fracture into the surrounding matrix. One is 3-pentanone, a symmetric short ketone, and the other is 2-ethylhexanol-4PO-15EO, a non-ionic surfactant with an ultra-short hydrophobe. They were used as low-concentration additives (approximately 1 wt%) to reservoir brine (RB) in this research.
Contact-angle experiments with oil-aged calcite surfaces showed that the two chemicals are comparable as wettability modifiers. For example, the surfactant solution was able to change the contact angle of oil droplets on oil-aged calcite surfaces from 134° to 47° within a day.
Coreflooding experiments using fractured limestone cores showed that the 3-pentanone solution resulted in more rapid oil recovery by water imbibition than the surfactant solution. The incremental oil recovery factor was 30.9% for 1.6 pore-volumes injected (PVI) of the 3-pentanone solution and 8.4% for 1.2 PVI of the chase RB. For the surfactant case, it was 23.6% for 1.6 PVI of the surfactant solution and 23.7% for 7.0 PVI of the chase RB.
The difference in oil recovery response between the two chemical solutions was attributed to their different characters as wettability modifiers; that is, the surfactant solution lowers the water/oil IFT from 11 mN/m to 0.21 mN/m, but the 3-pentanone solution does not. The 3-pentanone solution can keep the original water/oil IFT, and increase the capillary force for water imbibition by wettability alteration. The importance of lowering the water/oil IFT was observed during the extended chase RB injection after the surfactant slug. The oil recovery in the surfactant case was increasing even after 7.0 PVI of the chase RB.
Observations from field applications along with laboratory experiments have revealed the significant potential of the surfactant-assisted spontaneous imbibition (SASI) as an encouraging EOR method in unconventional liquid reservoirs (ULR). This study focuses on unveiling the target pore size range for SASI EOR through a combination of experimental results, computed tomography (CT), Scanning Electron Microscope (SEM) and Nuclear magnetic resonance (NMR) technologies. In addition, laboratory results were upscaled to the field-scale to evaluate the effectiveness of the SASI EOR in production enhancement in the Wolfcamp formation.
Eight SASI experiments were performed at reservoir temperature using different surfactants on quartz- and carbonate-rich side-wall core samples obtained from the Wolfcamp formation. Contact angle (CA), interfacial tension (IFT), and zeta potential were measured for the saturated core samples. CT-Scan technology is used to visualize the process of oil expulsion from the core plugs and generate core-scale simulation model to history-match laboratory results. SEM is used to match the NMR Pore Size Distribution (PSD) and obtain the Surface Relaxivity for each core sample. The target pore size range for SASI EOR in ULR is determined from NMR results. In addition, the laboratory results were upscaled to estimate the production enhancement through SASI EOR using the field scale model.
The primary production mechanism of SASI EOR is highly influenced by wettability alteration and IFT reduction. SASI experiments showed optimistic oil recovery results in both quartz-rich and carbonate-rich core samples with up to 36% and 17.5% of the Original Oil in Place (OOIP), respectively. The NMR technique is used to determine the pore size range from which the oil is produced during the SASI experiment. NMR results revealed that the pore size distribution plays a significant role in SASI EOR with the majority of the imbibed fluid is observed in smaller pores. The consideration of the pore size distribution has a significant impact on successful surfactant selection and a proper EOR process design in ULR. CT-scan technology is utilized to demonstrate the movement of the fluids inside the cores throughout the experiments. CT-scan technology is also used to validate the NMR results, which revealed a direct relation between CT imaging and NMR results. A CT-generated core-scale model was utilized to history-match laboratory results. The capillary pressure and relative permeability curves for the field-scale model were estimated from scaling group analysis and core-scale simulation. The simulation results indicate that SASI EOR has significant potential of enhancing oil production in ULR.
The novelty comes from the insight of the essential role of the pore size distribution in SASI EOR through CT and NMR technologies. Besides, a new workflow for surfactant selection is proposed to unveil the real potential of SASI in ULR.
We present an assessment of the impact of low-salinity brine osmosis on oil recovery in liquid-rich shale reservoirs. The paper includes: (1) membrane behavior of shales when contacted by low-salinity brine, (2) numerical model of osmosis mass transport for low-salinity brine, and (3) enhanced oil recovery (EOR) potential of low-salinity osmosis in liquid-rich shale reservoirs. Capillary osmosis causes low-salinity brine to be imbibed into the shale matrix; thus, forcing expulsion of oil from the rock matrix. This oil recovery process is described by a multi-component mass transport mathematical model consisting of advective and molecular transport of water molecules and dissolved ions. In the transport model, the activity-corrected diffusion of the brine solution is used to calculate the volume of brine imbibed into a shale core sample and the resulting expelled oil. We used the mathematical model to match oil recovery from two carefully designed brine-imbibition experiments conducted at Colorado School of Mines. We have concluded that, in oil-wet shale reservoirs, low-salinity brine invasion of the rock matrix is by osmosis rather than capillary force. Thus, osmosis is the only imbibing force that drives the low salinity brine into the reservoir rock matrix. Furthermore, we believe brine osmosis can potentially enhance oil recovery by expelling oil out of the rock matrix and into the micro-and macro-fractures existing in the stimulated reservoir volume.
Surfactant-based EOR has thus far been demonstrated to be a potentially effective solution to improve the hydrocarbon recovery from Unconventional Oil Reservoirs (UORs). The most discussed functions of a surfactant are either Interfacial Tension (IFT) reduction or Wettability (WTA) Alteration. However, studies of the accountable effects for the enhanced production are inadequate because of the peculiar properties of shale matrix, such as the extremely low permeability and initial wetness. In addition, the current studies mainly focused on the spontaneous imbibition (SI) because of the long experimental period and limited pressure applicability with the existing experimental apparatus.
This work is to study the process of shale oil EOR by adding surfactant additives with high confining pressures applied to an in-house designed set-up. The applied pressure was as high as 3000 psi and the surfactant was selected with a spectrum of IFT values. Two operational schemes were conducted: Forced Imbibition (FI) and Cyclic Injection (CI). For the forced imbibition study, constant pressure was applied to the experimental set-up throughout the whole experimental period. The final recovery was recorded at the end of each test. The cyclic injection is also referred to as ‘huff-n-puff’ technique. The pressure is applied and released with a periodic schedule and the recoveries were recorded after each cycle by volume.
The results were compared with that of regular SI experiments. It is noticed that oil productions through the CI technique is mostly effective and efficient. In addition, WTB-alteration is the dominating mechanism in both pressurized and atmospheric pressure cases, while surprisingly, IFT-reduction could be detrimental for the recovery enhancement due to the low capillary pressure. The results gave indicative suggestions on the selection of surfactant and engineering application design for a surfactant based EOR project in shale oil reservoirs.
The identification of the fluid fill history is a necessity for the development strategy of any field, in particular in the Middle East where tectonic history is often reported to affect fluid distribution and contacts in many fields. The fluid fill concept for a low permeability carbonate field has been re-evaluated and modified from a tilted contact interpretation with imbibition of the deepest unit to a field-wide flat contact and primary drainage saturation distribution. The oil volumes in the reservoir under study are sensitive to minor changes in the structure and fluid fill due to the relatively low structural dip and low permeability transitional nature of the reservoir. The paper highlights the importance of removing preconceptions in data analysis and ensuring consistency on interpretations between different available data sources. It also demonstrates how data quality could completely change the fluid fill concept.
The three main reservoir units of the Lower Shuaiba A, Lower Shuaiba B and Kharaib have been charged from two oil migration events. Structural changes post the first primary drainage are revealed by regional seismic images of the shallower horizons. Due to the rock low permeability, the water saturations are above irreducible value and the whole interval is in the "transition zone". Kharaib unit was believed to be imbibed by the aquifer after charge and was not developed. Three possible fluid fill scenarios were investigated: a) tilted contact due to structural changes post-charge, b) imbibition of the deeper interval, c) primary drainage with field-wide flat contact related to the second pulse of charge. Each scenario impacts the development of the three units positively or negatively. Water saturation logs vs. True Vertical Depth plots were the main diagnostic tool used to rule out fluid fill scenarios. The plots were used to recognise lateral changes of the saturation profile and investigate imbibition signatures. Production data were also used to cross check the expected fluid fill scenario. The resistivity tools’ types and mud resistivities were examined.