Das, Alolika (The University of Texas at Austin) | Nguyen, Nhut (The University of Texas at Austin) | Alkindi, Abdullah (PDO) | Farajzadeh, Rouhi (Shell Technology Oman) | Azri, Nasser (PDO) | Southwick, Jeffrey (Shell Global Solutions Intl. B.V.) | Vincent-Bonnieu, Sebastien (Shell Global Solutions Intl. B.V.) | Nguyen, Quoc P. (The University of Texas at Austin)
Chemical enhanced oil recovery (EOR) in carbonate reservoirs has always been technically and economically challenging. Conventional Alkaline-Surfactant-Polymer (ASP) flooding has limited application in low permeability (2-20 mD) and high salinity formations (~200,000 ppm TDS) with a large concentration of divalent cations. Also injectivity into such low permeability reservoirs can be a significant problem with polymer solutions.
The process of low tension gas (LTG) in tight carbonates has exhibited good microscopic displacement and mobility control. It combines interfacial tension (IFT) reduction with improved mobility control by in-situ generation of foam in low-permeable heterogeneous formations. This process has been tested in the lab for a Middle Eastern carbonate reservoir, which is the subject of this paper. This strategy has been tested through either co-injection or alternating injection of slug/drive surfactant solution and gas (CO2, N2, or hydrocarbon) at low foam quality (high water content). A successful surfactant screening was performed to select the optimum surfactant formula that exhibits ultra-low IFT, good aqueous stability, and low microemulsion viscosity. The formulation allows tailoring of optimal salinity for ultra-low oil-water IFT to the variation of formation and produced water salinity. Core flood experiments have been performed, which demonstrated favorable mobilization and displacement of residual oil. Tertiary recoveries of up to 85% on remaining oil were achieved for cores with permeability less than 10 mD. An innovative experimental method was also developed to achieve high initial oil saturation in tight rocks.
Al-Rashdi, Yaqoob Salem (Petroleum Development Oman LLC) | AL Kindi, Abdullah (Petroleum Development Oman LLC) | AL Bulushi, Sameer (Petroleum Development Oman LLC) | Azri, Nasser (Petroleum Development Oman LLC) | Te Riele, Paul M (Shell Technology Oman)
Heavy oil fields with complex geology present a great challenge for a commercial development. The field described in the paper is a heterogeneous, sparsely fractured carbonate field with oil viscosity of 5,000 –10,000 cP. Initial production test proved that the field cannot be commercially developed using conventional development primary and secondary recovery technologies.
A number of EOR recovery processes have been reviewed for applicability to this field. A fit for purpose uncertainty analysis on key parameters lead to the conclusion that thermal recovery methods are not technically feasible mainly due to steam confimenent issues. A solvent based EOR development scheme was identified as a potential recovery route for such reservoir environment. A feasibility study was conducted to determine whether solvent injection is attractive under a number of realistic subsurface realizations and completion strategies. This study resulted in a number of activities to derisk uncertainties and come to quality decisions towards a solvent development.
Series of field tests have been conducted to mitigate some of the risks associated with the solvent development. Firstly, given the low permeability and low oil mobility, the presence of mobile water is essential in order to inject the solvent and contact the oil with the solvent. Water injection tests were carried out to demonstrate the presence of mobile water in all different reservoir zones and confirmed matrix injectivity is possible. A next step is to utilize the mobile water to inject a solvent into the reservoir and contact the oil accordingly for which a solvent test is planned using a mixture of xylene and diesel. A xylene-diesel mixture was selected as this showed in laboratory tests first contact miscibile with the field crude oil and is readily available for field application. The objectives of this single well injection test are to 1) confirm and quantify solvent injectivity, 2) prove heavy oil mobilization through solvent EOR methods from carbonate reservoir settings and 3) to determine near wellbore sweep efficiency of solvents injected into long horizontal wells. If successful a multi well continuous injection trial will be designed and executed.
This paper describes the design and analysis of the single well solvent injection test for this heavy oil carbonate field. It also describes the experimental lab work conducted to confirm xylene-diesel compatibility with the field crude oil and its suitability for application in a solvent EOR development derisking.
Suijkerbuijk, B.M.J.M. (Shell Global Solutions International) | Sorop, T.G. (Shell Global Solutions International) | Parker, A.R. (Salym Petroleum Development) | Masalmeh, S.K. (Shell Technology Oman) | Chmuzh, I.V. (Salym Petroleum Development) | Karpan, V.M. (Salym Petroleum Development) | Volokitin, Y.E. (Salym Petroleum Development) | Skripkin, A.G. (NIPINEFT)
Low Salinity Waterflooding (LSF) is a rapidly emerging IOR/EOR technology that improves oil recovery by lowering the injection water salinity. The desalination process provides additional advantages such as reduction of souring, scaling and of injectivity decline. Proper screening of LSF for a particular field requires performing laboratory SCAL tests to (i) measure relative permeability curves used in the models to quantify the field scale benefit of LSF and (ii) de-risk for the potential of formation damage by clay swelling and deflocculation.
Shell has started a campaign of screening the whole waterflooding (WF) portfolio [SPE 165277] for LSF. One of the screening candidates is the West Salym field, operated by Salym Petroleum Development (SPD; JV Shell/GazPromNeft) which is currently producing under waterflooding. SPD is already assessing IOR/EOR options to increase the WF recovery factor. While ASP is being matured as the main EOR option [SPE 162067], several LSF laboratory tests have been recently performed to assess the potential of this technique, given the presence of a large aquifer (Cenomanian) in the vicinity of the field, which can serve as a plentiful source of LS injection brine after desalination.
This study focuses on the initial Salym LSF SCAL tests performed at reservoir conditions using representative reservoir core and crude oil, with a synthetic brine that reflects the formation and injection water compositions accurately. The experiments comprised a suite of Amott and coreflood tests, following the internal Shell LSF protocol.
The tests clearly show a positive LSF effect, with additional oil produced in absence of formation damage. The data indicates that LSF causes a shift in wettability towards a more water-wet behavior, and results in a reduction of Sorw.
The paper discusses the details of the experimental procedure. Numerical simulations were employed to obtain relative permeability curves using the history matching of the coreflooding tests. Finally, relative permeabilties are used for upscaling to the full field scale. The results are discussed for various possible scenarios.
Masalmeh, Shehadeh K. (Shell Technology Oman) | Sorop, Tibi (Shell) | Suijkerbuijk, Bart M. J. M. (Shell) | Vermolen, Esther C. M. (Shell International Ltd.) | Douma, Sippe (Shell International E&P Co.) | van del Linde, H. A. (Shell Abu Dhabi BV) | Pieterse, S. G. J. (Shell Abu Dhabi BV)
Low Salinity Flooding (LSF) is an emerging technology to improve oil recovery for both sandstone and carbonate reservoirs. Extensive laboratory experiments investigating the effect of LSF are available in the literature. To quantify the low salinity effect, spontaneous imbibition and/or tertiary waterflooding experiments have been reported. In only a few published cases, the experimental data was interpreted using numerical simulation to derive relative permeability curves for both low and high salinity water, to be used in field simulation. A critical review of the literature data shows a wide spread in the LSF response in both pressure and recovery. Moreover, most of the flooding experiments reported in the literature are performed at a low flow rate, of ~1 ft/day, which may lead to a significant capillary end effect and, consequently, to a possible overestimation of the LSF effect.
The focus of this paper is on: 1- The experimental procedures used for proper evaluation of the LSF effect; 2- Reporting experimental data performed on sandstone samples in both tertiary and secondary mode waterflood; 3-The numerical interpretation of the laboratory data to obtain relative permeability and capillary pressure curves for both high salinity (HS) and low salinity (LS) water, to be used in reservoir simulation to quantify the benefit of LSF on reservoir scale and 4- Investigating whether the tertiary flooding experiments can be used to derive relative permeability curves for both HS and LS waterflooding.
The main conclusions of the study are: 1- While spontaneous imbibition (SI) experiments could provide an indication of a potential low salinity effect, they are not sufficient to quantify the effect in flooding experiments; 2- The LSF effect measured during low rate flooding experiments (i.e., field rate) is not representative for the field scale as it is usually dominated by capillary end effect. Therefore, the low rate (raw) coreflood data will suggest a larger LSF benefit than would actually be the case; 3- The tertiary mode experiments cannot be used to derive the LS relative permeability curves as it only spans a narrow saturation range during LSF and 4- Both tertiary and secondary mode corefloods performed using multi-rates are required to obtain relative permeability curves for HS and LS water.
Low salinity waterflooding (LSF) is an emerging technology in which the salinity of the injected water is optimized to improve oil recovery over conventional waterflooding. Over the last two decades several groups have published laboratory and field data which show extra oil recovery upon injection of LS water. However, a wide range of responses in the extra oil recovery is reported in the literature, from 0 to more than 20%. To extrapolate laboratory results to the field scale and to separate several potential underlying LSF mechanisms, measuring and accounting for the pressure drop over the core during flooding experiments is essential. In a number of cases reported in the literature no pressure data was shown. In the cases when the pressure data was available, a wide range of pressure responses was observed. In some cases a pressure increase was observed once low salinity was injected. The effect of such pressure increases on laboratory results was rarely discussed.
It is widely recognized that the determination of the amount and distribution of residual oil saturation (Sorw) is a significant factor in managing ongoing waterflooding and the selection of EOR methods that are applicable and economically suitable for oil reservoirs. Laboratory core flooding tests are often used to estimate the amount of Sorw. The same core samples are then usually subjected to EOR flooding experiments to estimate the extra amount of oil that can be recovered with the specific EOR option. Failure to accurately determine Sorw will lead to wrong estimates of recovery factor of both waterflooding and the subsequent EOR methods.
Significant amount of data is available in the literature on determining Sorw and on the critical capillary or bond number to mobilize Sorw. However, most of the data are measured on sandstone rock and for water-wet conditions. In this study the focus is on 1- determination of Sorw in the laboratory for carbonate reservoirs, 2- The factors that affect Sorw, including capillary end effect, capillary and Bond numbers, initial oil saturation, rock permeability, rock heterogeneity and experimental techniques and 3- The use of numerical simulation as tool to aid proper interpretation of laboratory experiments.
The main conclusions of the study are: 1- Performing the water flooding experiments at reservoir rates of ~1 ft/d will lead to overestimation of Sorw as the data can be dominated by capillary end effect; 2- The relative contribution of capillary end effect increases as the permeability increases especially for heterogeneous carbonate rocks; 3- There is no correlation between Sorw and rock permeability or porosity for the case understudy; 4- The critical capillary or bond number of non-water-wet carbonates is much higher than those reported in the literature for water-wet sandstone; thus experiments can be performed at higher rates than those expected in the field without the risk of de-saturation of Sorw and 5- Once an equilibrium between capillary and viscous (or gravity) forces is established, the remaining oil saturation is independent of the number of pore volumes injected.
The data presented in this paper has significant impact on the design of any subsequent EOR process. It shows that the EOR target (after waterflood) is significantly reduced if the measurements are performed using high rates (or high centrifuge speed) to overcome capillary end effect. Moreover, for non-water wet rock surfactant flooding will require much higher reduction in IFT to mobilize residual oil saturation than for water-wet rocks.
Sorop, Tiberiu Gabriel (Shell Global Solutions International) | Suijkerbuijk, Bart M.J.M. (Shell Global Solutions International) | Masalmeh, Shehadeh K (Shell Technology Oman) | Looijer, Mark T. (Shell Global Solutions International) | Parker, Andrew R (Shell Global Solutions International) | Dindoruk, Deniz M (Shell Exploration & Production Co) | Goodyear, Stephen Geoffrey (Shell E&P UK) | Al-Qarshubi, Ibrahim S.M. (Shell Global Solutions International)
Low Salinity Waterflooding (LSF) is an emerging IOR/EOR technology that can improve oil recovery efficiency by lowering the injection water salinity. Field scale incremental oil recoveries are estimated to be up to 6% STOIIP. Being a natural extension of conventional waterflooding (WF), LSF is easier to implement than other EOR methods. However, the processes of screening, designing and executing LSF projects require an increased operator competence and management focus compared to conventional waterflooding. This paper discusses the practical aspects of deploying LSF in fields, focusing on the maturation stages, while highlighting the key success factors.
LSF deployment starts with a portfolio screening against specific surface and subsurface screening criteria to prioritize opportunities. Next, the identified opportunities are run through reservoir conditions SCAL tests to quantify the LSF benefits, while de-risking the potential for any injectivity loss due to clay swelling or deflocculation. Standardized LSF SCAL protocols have been incorporated into the general WF guidelines, so that any suitable new WF project conducts LSF SCAL. For mature waterfloods, this SCAL program provides additional reservoir condition relative permeability data, enabling operating units to optimize well and reservoir management (WRM). The next steps in the process are production forecasting, facilities design, and project economics for the LSF opportunity. The multidisciplinary nature of LSF deployment requires integrated (sub)surface technology teams closely collaborating with R&D and asset teams. The standardization of the facilities design, including cost models, can significantly accelerate the deployment effort.
In Shell, LSF is currently at different stages of deployment around the world and across the whole spectrum of WF projects, from the rejuvenation of brown fields to green field developments (offshore and onshore). The LSF deployment effort is combined with the screening of other EOR technologies, to identify where LSF may be able to unlock additional value by creating the appropriate conditions for subsequent chemical flooding.
In a layered, 2D heterogeneous sandpack with a 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil in place (OOIP) because of injected water flowing through the high-permeability zone, leaving the low-permeability zone unswept. To enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT). Once IFT was reduced to ultralow values, the adverse effect of capillarity retaining oil was eliminated. Gravity-driven vertical countercurrent flow then exchanged fluids between high- and low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foam flood was 94.6% OOIP, even though foam strength was weak. Recovery with chemical flood (incremental recovered oil/waterflood remaining oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous-force-dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental to foam generation. However, the addition of lauryl betaine to NI (NIB) at a weight ratio of 1:2 (NI:lauryl betaine) made the new blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT-reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1D homogeneous sandpacks and in an oil-wet heterogeneous layered system with a 34:1 permeability ratio.
Low sa linity waterflooding (LSF) research has been gaining more momentum in recent years for both sandstone and carbonate reservoirs. Published laboratory data and field tests have shown an increase in oil recovery by changing injected brine salinity, especially for sandstone reservoirs. It is widely accepted that low salinity water alters the wettability of the reservoir rock from less to more water-wet conditions, oil is then released from rock surfaces and recovery is increased. The main objectives of the current study are to: test the potential of increasing oil recovery by LSF of a carbonate reservoir and to investigate the factors that control it. The impact of LSF on oil recovery was investigated by conducting coreflood and spontaneous imbibition experiments at 70 oC using core samples from a carbonate reservoir, crude oil and synthetic brine (194,450 ppm) which was mixed with distilled water in four proportions twice, 5 times, 10 times and 100 times dilution brines. Moreover, both crude oil/brine interfacial tension measurements (IFT) and ionic exchange experiments were carried out at room temperature (25 oC).
The results of the study show higher oil recovery as a result of reducing injected water salinity in both coreflood and spontaneous imbibition experiments. Coreflood experiments showed an increase in oil recovery by 3 to 5 % of OOIP, while spontaneous imbibition experiments showed an increased by 16 to 21 %. Additionally, spontaneous imbibition experiments provide direct evidence of wettability change by the LSF. The study also shows that the increase in oil recovery was obtained at much higher water salinity than the one observed in the case of sandstone rock.
Masalmeh, Shehadeh K. (Shell Technology Oman) | Wei, Lingli (Shell International Exploration & Production B.V.) | Hillgartner, Heiko (Petroleum Development Oman) | Al-Mjeni, Rifaat (Shell) | Blom, Carl P.A. (Shell Intl E&P)
Enhanced oil recovery (EOR) has become increasingly important to maintain and extend the production plateaus of existing oil reservoirs. Simulation models for EOR studies require the right level of spatial resolution to capture reservoir heterogeneity. Data acquired from the dedicated observation wells are essential in defining the required resolution to capture reservoir heterogeneity. For giant reservoirs with long production history, their full field models usually have grid block sizes that are of similar scale as the distance between injectors and observation wells, with the consequence of losing the value of the time lapse saturation logs from dedicated observation wells. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must.
The objective of this paper is to present an improved and integrated reservoir characterization, modelling and water and gas injection history matching procedure of a giant Cretaceous carbonate reservoir in the Middle East. The applied workflow integrates geological, petrophysical, and dynamic data in order to understand the production history and the remaining oil saturation distribution in the reservoir. Large amounts of field data, including time lapse saturation logs from observation wells, have been collected over the last decades to provide insight into the sweep efficiency and flow paths of the injected water.
Iterative simulations were performed to investigate different scenarios and various sensitivities with each iteration involving an update of the static model to honor both the dynamic and core/log data. While applying this iterative process it was also acknowledged that conventional core data (e.g. 1 plug per foot) may not capture the high permeability streaks in these heterogeneous reservoirs that control much of the reservoir flow behaviour, hence much denser plugging and core examination is required. In addition, permeability upscaling procedures need to take into account the fact that core plugs may not represent the effective permeability of the larger connected vuggy pore systems.
The improved understanding of reservoir heterogeneity, the more robust reservoir characterization, and the improved history matching demonstrates that a better representation of reservoir dynamics is achieved. This provides a solid platform for designing and planning future EOR schemes.
Carbonate reservoirs contain more than 50% of world's remaining conventional hydrocarbon reserves and on average have relatively low recovery factors. With the insight that the era of "easy oil?? (conventional oil and natural gas that are relatively easy to extract) is phasing out, enhanced oil recovery (EOR) becomes increasingly important to maintain and extend the production plateaus from existing oil reservoirs. EOR technologies, however, require a refined understanding of reservoir heterogeneities and dynamic field performance. Simulation models for EOR studies need to have the right level of resolution and details. Often, we find that for a giant reservoir with a long waterflood history, working with full field models with coarse simulation grids is not adequate to understand the reservoir performance and calibrate the static model. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must.
Stoll, Werner M. (Shell Technology Oman) | al Shureqi, Hamad (Shell Technology Oman) | Finol, Jose (Shell Technology Oman) | Al-Harthy, Said A.A. (Petroleum Development Oman) | Oyemade, Stella Nneamaka (Petroleum Development Oman) | de Kruijf, Alexander (Petroleum Development Oman) | van Wunnik, Johan (Petroleum Development Oman) | Arkesteijn, Fred (Shell International E&P) | Bouwmeester, Ron (Shell International E&P) | Faber, M.J. (Shell International E&P)