Skrettingland, K. (Statoil ASA) | Ulland, E. N. (Statoil ASA) | Ravndal, O. (Statoil ASA) | Tangen, M. (Statoil ASA) | Kristoffersen, J. B. (Statoil ASA) | Stenerud, V. R. (Statoil ASA) | Dalen, V. (Statoil ASA) | Standnes, D. C. (Statoil ASA) | Fevang, Ø. (Statoil ASA) | Mevik, K. M. (Knutsen Subsea Solutions) | McIntosh, N. (Knutsen Subsea Solutions) | Mebratu, A. (Halliburton) | Melien, I. (Halliburton) | Stavland, A. (Intl Research Inst of Stavanger)
Declining oil production and increasing water cut in mature fields highlight the need for improved conformance control. Here we report on a successful in-depth water diversion treatment using sodium silicate to increase oil recovery at the Snorre field, offshore Norway, utilizing a new operational concept of using a stimulation vessel as a platform for the large-scale injection into a subsea well. A custom modified 35,000 DWT shuttle tanker was employed for the field pilot. This paper describes the vessel preparations and the large-scale interwell silicate injection operation. The operational aspects of the large-scale interwell silicate injection include; identification of injection vessel requirements, major vessel modifications, chemical logistic, general logistics to site, major equipment set-up on vessel, subsea connection, mixing and pumping schedules, onsite QC, and real time monitoring. Experience from these operations and lessons learned are included in this paper.
After the injection of approximately 400,000 Sm3 (113,000 Sm3 preflush, followed by 240,000 Sm3 of sodium silicate gelant and 49,000 Sm3 of postflush fluid) at injection rates up to 4,000 Sm3/d, the injection from the vessel was stopped and the well was put on regular seawater injection. Following more than two years of regular production, transient pressure measurements, tracer testing and water cut data are presented from the ongoing comprehensive data acquisition program. These results demonstrate clearly the achieved in-depth flow diversion through a delayed breakthrough of injected tracers and lower water cut in the relevant production well.
Waterflood implementation accounts for more than half of the oil production worldwide. Despite the observations and extensive research from a large number of floods and thousands of simulation studies, managing waterfloods and Enhanced Oil Recovery (EOR) floods is still a technical challenge. A major contributor to this challenge are waterflood induced fractures (WIF). Managing waterfloods is a multivariable problem although WIF are one aspect, it is by no means the only controlling factor.
The best evidence that WIF are one of the main factors controlling flow in reservoirs is the insensitivity of injection pressure to injection rates. With our experience, in hundreds of waterfloods, we have frequently observed this phenomenon in the field data. If fluid flow depended on diffusive Darcy flow alone, we would expect higher injection rates with higher injection pressures. However, it is common to observed relatively constant injection pressures over a wide range of water injection rates. Rapid well communication and changes in water cuts that vary with injection rates also support an interpretation of high permeability induced fractures between injector and producer. In some reservoirs, interwell tracer data can be used to determine the influence of induced fracture features. The interwell tracers usually show very fast water movement.
Induced fractures in waterfloods and EOR projects can be caused by a number of mechanisms such as but not limited to, pressure depletion, changing pressure regimes, thermal effects, or plugging effects. These fractures can either be beneficial to the reservoir performance or effect performance negatively. Benefits include improved injectivity and increased throughput of the displacing fluid. Negative effects can come in the form of reduced volumetric sweep efficiency, impaired ultimate recovery or injected fluid losses out of zone.
Case studies, theory, and available literature from Western Canada will be reviewed in order to suggest and improve reservoir management strategies for waterfloods. We have completed hundreds of waterflood feasibility, waterflood management and EOR flood studies worldwide and continue to be amazed and humbled by the complexity that many waterfloods and EOR floods exhibit due to induced fracturing. WIF and EOR induced fractures (EIF) are common and should be analysed to optimize production. Growth of the WIF, response to waterflood with the presence of WIF, implication of WIF and reservoir management are the main areas which will be addressed.
Al Ayesh, A. H. (Department of Geoscience and Engineering, Delft University of Technology) | Salazar, R. (Department of Geoscience and Engineering, Delft University of Technology) | Farajzadeh, R. | Vincent-Bonnieu, S. | Rossen, W. R.
Foam can divert flow from higherto lower-permeability layers and thereby improve vertical conformance in gas-injection enhanced oil recovery. Recently,
The effectiveness of diversion varies greatly with injection method. In a SAG (surfactant-alternating-gas) process, diversion of the first slug of gas depends on foam behavior at very high foam quality. Mobility in the foam bank during gas injection depends on the nature of a shock front that bypasses most foam qualities usually studied in the laboratory. The foam with the lowest mobility at fixed foam quality does not necessarily give the lowest mobility in a SAG process. In particular, diversion in SAG depends on how and whether foam collapses at low water saturation; this property varies greatly among the foams reported by Kapetas et al. Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This of course favors diversion away from high-permeability layers that receive a large surfactant slug, but there is an optimum surfactant slug size: too little surfactant and diversion from high-permeability layers is not effective; too much and mobility is reduced in low-permeability layers, too. For a SAG process, it is very important to determine if foam collapses completely at irreducible water saturation.
In addition, we show the diversion expected in a foam-injection process as a function of foam quality. The faster propagation of surfactant and foam in the higher-permeability layers aids in diversion, as expected. This depends on foam quality and non-Newtonian foam mobility and varies with time of injection. Injectivity is extremely poor with foam injection, but is not necessarily worse than waterflood in some effective SAG foam processes
Yeganeh, Mohsen (ExxonMobil Research and Engineering Co.) | Hegner, Jessica (ExxonMobil Research and Engineering Co.) | Lewandowski, Eric (ExxonMobil Research and Engineering Co.) | Mohan, Aruna (ExxonMobil Research and Engineering Co.) | Lake, Larry W. (The University of Texas at Austin) | Cherney, Dan (ExxonMobil Research and Engineering Co.) | Jusufi, Arben (ExxonMobil Research and Engineering Co.) | Jaishankar, Aditya (ExxonMobil Research and Engineering Co.)
A capillary desaturation curve (CDC) depicts the relationship between residual oil saturation, Sor, (i.e. oil left behind in a well-swept permeable medium) and capillary number. A CDC is one of the most fundamental curves of oil recovery as it reveals flow conditions required for good oil displacement in porous media. Despite the importance of this critical curve, the fundamentals describing the physics of a CDC are still incomplete.
We present a physical model to describe the capillary desaturation curve. The model balances the capillary pressure and applied viscous stresses caused by flow and takes advantage of contact angle hysteresis that occurs in porous media. It defines a critical oil ganglia length that depends inversely on capillary number and depends on porosity, permeability, and wettability. We have combined the critical oil ganglia expression and ganglia length distribution in porous media to arrive at an expression for the capillary desaturation curve. The model suggests that when a trapped oil ganglion is larger than the critical ganglia length, the applied pressure difference can mobilize the trapped oil ganglion. We describe the differences and similarities between our critical ganglia length expression and previously reported expressions. The model describing the relationship between residual oil saturation and capillary number was successfully verified with microfluidic experiments using various crude oils and displacing fluids. We have also demonstrated that the model applies to previously reported coreflood CDCs from sandstone and carbonate media. Extension of the model led to a single curve representation of variations in Sor with reduced pressure. This representation is independent of the chemistry of the displacing fluid.
Jong, Stephen (University of Texas at Austin) | Nguyen, Nhut M. (University of Texas at Austin) | Eberle, Calvin M. (University of Texas at Austin) | Nghiem, Long X. (Computer Modelling Group Ltd.) | Nguyen, Quoc P. (University of Texas at Austin)
Low Tension Gas (LTG) flooding is a novel EOR process which can address challenging reservoir conditions such as high salinity, high temperature, and tight rock. Current process understanding is limited, and a joint experimental and modeling approach allows for both interpretation and insight into the complex interactions between the key process parameters of salinity gradient, foam strength, microemulsion phase behavior, and phase desaturation in order to achieve a physically correct and predictive process model.
We performed a series of corefloods in high permeability Berea sandstones (~500 mD) to demonstrate the impact of salinity gradient on the LTG process and interactions between key mechanisms such as microemulsion phase behavior and foam stability. In order to provide additional insight into the experimental study and improve understanding of the LTG process, we used our newly developed LTG simulator which we built within CMG GEM.
The results demonstrate that decreasing slug injection salinity can lead to a 15% increase in residual oil in place (ROIP) recovery over a slug injected at optimum salinity, with earlier breakthrough and steeper recovery slope. In addition, there is evidence of a late time pressure buildup as salinity is decreased through mixing with drive salinity which is indicative of increasing foam stability. This may be due to an inverse relationship between oil-water IFT and foam stability and thus designing an optimal salinity gradient for an LTG process requires balancing oil mobilization due to ultralow IFT and effectively displacing mobilized oil with adequate foam mobility control.
We introduce and show the strength our compositional LTG simulator in a pioneering laboratory and simulation study that sheds light on the interaction between salinity, microemulsion phase behavior, and foam strength. Our conclusions indicate a significant departure from traditional ASP understanding and methodology when designing an LTG salinity gradient and serve as a foundation for future investigation.
Mukherjee, Joydeep (The Dow Chemical Company) | Nguyen, Quoc P. (The University of Texas at Austin) | Scherlin, John (Fleurde Lis Energy) | Vanderwal, Paul (The Dow Chemical Company) | Rozowski, Peter (The Dow Chemical Company)
A supercritical CO2 foam pilot, comprised of a central injection well in an inverted 5-spot pattern, was implemented in September 2013 in Salt Creek field, Natrona County WY. In this paper we present a thorough analysis of the pilot performance data that has been collected to date from the field. A monitoring plan was developed to analyze the performance of the pilot area wells before and after the start of the foam pilot. The injection well tubing head pressure was controlled to maintain a constant bottom hole pressure and the fluid injection rates were monitored to capture the effect of foam generation on injectivity. Inter-well tracer studies were performed to analyze the change in CO2 flow patterns in the reservoir. Production response was monitored by performing frequent well tests. The CO2 injection rate profile monitored over several WAG cycles during the course of the implementation clearly indicates the formation and propagation of foam deep into the reservoir. CO2 soluble tracer studies performed before and after the start of the foam pilot indicate significant areal diversion of CO2. The production characteristics of the four producing wells in the pilot area indicate significant mobilization of reservoir fluids attributable to CO2 diversion in the pattern. The produced gas-liquid ratio has decreased in all four of the producing wells in the pattern. Analysis of the oil production rates shows a favorable slope change with respect to pore volumes of CO2 injected. Segregation of CO2 and water close to the injection well seems to be the primary factor adversely affecting CO2 sweep efficiency in the pilot area. Foam generation leads to a gradual expansion of the gas override zone. The gradual expansion of the gas override zone seems to be the principal mechanism behind the production responses observed from the pilot area wells.
Jahanbakhsh, A. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Sohrabi, M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Fatemi, S. M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Shahverdi, H. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University)
Gas/oil interfacial tension (IFT) is one of the most important parameters that impact the performance of gas injection in an oil reservoir. The choice or design of the composition of the gas injected for EOR is usually affected by the gas/oil IFT. In conventional reservoir simulation, IFT does not explicitly appear in the equations of flow and therefore its effect must be captured by the shape and values of relative permeability curves. A few studies have been previously reported for IFT effect on two-phase flow but very little have been done to investigate gas/oil IFT effect under three-phase flow conditions. The objective of this study is, firstly, to investigate the impact of gas/oil IFT reduction on two- and three-phase relative permeabilities using coreflood experiments. Secondly, to investigate the effect of changing gas/oil IFT value (immiscible and near-miscible) on the performance of WAG injections and residual oil saturation reduction at laboratory scale.
Two- and three-phase (WAG) coreflood experiments have been performed on water-wet and mixed-wet cores at three different gas/oil IFT conditions. These experiments were conducted on Clashach sandstone cores with a permeability of 65 and 1000 mD. The two- and three-phase relative permeabilities were estimated from the results of the coreflood experiments using our in-house software (3RPSim) and were compared with each other on the basis of their gas/oil IFT values. Moreover, the impact of gas/oil IFT reduction on the performance of gas and WAG injection and in particular on the reduction of residual oil saturation was investigated. The results of our studies were also compared with the existing literature on the laboratory investigation of WAG injection.
The results show that in two-phase gas/oil systems, the relative permeability of non-wetting phase is more affected by a reduction in the gas/oil IFT compared of the relative permeability of the wetting phase. Comparing the curvature of the gas and oil relative permeability curves shows that although the curvature decreases by a reduction in gas/oil IFT but it is still far away from straight line even at ultra-low IFT values. In three-phase flow system, reduction of gas/oil IFT affects the relative permeabilities of all the three phases (gas, oil and water).
The results show that at high gas/oil IFT or immiscible WAG injection, the most reduction in residual oil saturation is achieved in the first injection cycle and further WAG cycles do not result in a significant additional reduction in oil saturation. On the contrary, at low gas/oil IFT or near-miscible WAG injection, the residual oil saturation keeps decreasing as the number of WAG cycles increases. Moreover, the reduction in residual oil saturation was more effective when the immiscible WAG experiments started with gas injection (secondary WAG).
Piñerez T., Iván D. (University of Stavanger) | Austad, Tor (University of Stavanger) | Strand, Skule (University of Stavanger) | Puntervold, Tina (University of Stavanger) | Wrobel, Stanislaw (University of Stavanger) | Hamon, Gérald (Total E&P)
Low salinity water injection in sandstone is an emerging technology just on the verge of being implemented full field in the UK and in Alaska, USA. Laboratory studies are important for providing relevant and well interpreted data before performing the field trial. However, laboratory investigations show varying results on low salinity EOR, most probably because of a limited understanding of the nature of the process. Recently we have published a "Smart Water" EOR mechanism where pH changes at the rock surface is inducing the wettability alteration, improving positive capillary forces and microscopic sweep efficiency. Researchers have experienced rather poor low salinity EOR effects from 17 different sandstone outcrops from the USA.
In this work we have investigated 6 of the same 17 outcrops, and according to our chemical understanding, some factors are more important for observing LS EOR effects in sandstone. It is the increase in pH, ?pH, obtained when the high salinity (HS) formation water is displaced by the low salinity (LS) injection water, and it is the initial pH and the amount of active cations (Ca2+) in the formation water that are related to the initial wetting.
We have established a link between the poor low salinity EOR effect from all 6 outcrops and the corresponding pH change observed when switching from high salinity to low salinity injection water. The presence of different types of minerals such as clay, feldspars and anhydrite will influence the pH change, and must be taken into account. Additionally, we have seen that the formation water composition has strong influence on the low salinity EOR effect. Using a formation water with salinity like seawater (FW1 ~35 000 ppm) showed only a minor tertiary low salinity EOR effect, 0.74 %OOIP, corresponding to a low pH gradient of 0.5. While experiments using a high salinity formation water (FW2 ~100 000 ppm) showed a 5 % OOIP recovery, corresponding to a larger pH gradient of 2.0.
The results observed are in agreement with the suggested chemical mechanism for the low salinity EOR effect, confirming that it is the pH gradient that triggers the low salinity EOR effect. In addition, the pH screening test used in this work proved once again to be a reliable tool to evaluate the low salinity EOR potential.
Ghasemi, M. (Petrostreamz AS) | Astutik, W. (Petrostreamz AS) | Alavian, S. A. (PERA AS) | Whitson, C. H. (PERA AS/NTNU) | Sigalas, L. (Geological Survey of Denmark and Greenland) | Olsen, D. (Geological Survey of Denmark and Greenland) | Suicmez, V. S. (Maersk Oil & Gas A/S)
This paper presents a novel technique to determine multi-component diffusion coefficients for CO2 injection in a North Sea Chalk Field (NSCF) at reservoir conditions. Constant volume diffusion (CVD) method is used, consisting of an oil-saturated chalk core in contact with an overlying free-space, which is filled with the CO2. The experimental data are matched with an EOS-based compositional model.
Transport by diffusion controls the dynamics of the constant-volume system, together with phase equilibria, allowing a consistent estimation of diffusion coefficients needed to describe the observed changes in system pressure.
We conduct two experiments at reservoir condition: one utilizes a core plug saturated with live-oil, and the other with stock tank oil (STO). Once the experiments are completed, EOS-based compositional simulation is performed to match the experimental data using the oil and gas diffusion coefficients as history matching parameters. The modeling work is conducted with a commercial reservoir simulator using a two dimensional radial grid model to describe the experimental setup.
The experiment utilizes a vertically-oriented core holder with a height of 92 mm and 37.6 mm in diameter. An outcrop chalk core with a sealing sleeve is mounted in the core holder, which has the same diameter and a height of 64.6 mm, thus resulting in an overlying void space. The system is initially saturated with oil at reservoir condition. CO2 is then injected from the top, forming an overlying CO2 chamber, and displacing oil towards the bottom of the core holder. Once CO2 fills the overlying bulk space, the system is isolated with no further injection or production.
The CO2 and oil reach and remain in equilibrium locally at the gas-oil interface throughout the test, initiating and maintaining the diffusion mechanism. Diffusion of CO2 into the oil results in a decreasing pressure, which is the main history matching parameter.
The multi-component diffusion coefficients are found to match the model pressure-time prediction to the experimental data. This suggests the modelling workflow incorporates a representative EOS model and the main transport dynamics controlled by diffusion are being treated properly.
The two main challenges in the modeling are (1) the limitation on setting an appropriately-high permeability for the CO2 chamber, and (2) the reservoir simulator neglects compositional dependency of diffusion coefficients.
Proper simulation of CO2 injection in fractured chalk reservoirs requires the ability to model multi-component diffusion accurately. The proposed CVD-method provides such modeling capabilities. Our modeling and experimental work indicate the novelty of the CVD method to determine the diffusion coefficients of a system where diffusion is the dominant displacement mechanism. The fact that the oil is contained within a low-permeability chalk sample reduces density-driven convection that could result due to non-monotonic oil density changes as CO2 dissolves into the oil.
Carbonate rocks are typically heterogeneous at many scales; hence foams have the potential to improve both oil displacement efficiency and sweep efficiency in carbonate rocks. However, foams have to overcome two adverse conditions in carbonates: oil-wettability and low permeability. This study evaluates several foam formulations that combine wettability alteration and foaming in low permeability oil-wet carbonate cores. Contact angle experiments were performed on oil-wet calcite plates to evaluate the wettability altering capabilities of the surfactant formulations. Static foam stability tests were conducted to evaluate their foaming performance in bulk. Finally, oil displacement experiments were performed using Texas Cream and Estaillades Limestone cores with crude oil. Two different injection strategies were studied in this work: alternating gas-surfactant-gas injection and co-injection of wettability alteration surfactant with gas at a constant foam quality. Cationic surfactants DTAB and BTC altered the wettability of the oil-wet calcite plate to water-wet, but were ineffective in forming foam. The addition of a non-ionic surfactant Tergitol NP helped in the foaming ability of these formulations. In-house developed Gemini cationic surfactant GC 580 was able to alter the wettability from oil-wet to water-wet and also formed strong bulk foam. Static foam tests showed increase in bulk foam stability with the addition of zwitterionic surfactants to GC 580. Oil displacement experiments in oil-wet carbonate cores revealed that tertiary oil-recovery with injection of a wettability-altering surfactant can recover a significant amount of oil (about 20–25% OOIP) over the secondary water flood and gas flood. The foam rheology in the presence of oil suggested propagation of only weak foam in oil-wet low permeability carbonate cores.