Experiments involving three-phase flow in porous media including Water-Alternating-Gas (WAG) injection are time-consuming andexpensive. Therefore, it is not feasible to experimentally consider all alternative injection schemes of these processes for different wettability and IFT (interfacial tension) conditions. The standard approach is to perform numerical simulations using models preferably tuned by laboratory data and experiments.
We present the results of a series of two-phase (WF and GF) and three-phase (WAG and SWAG) coreflood experiments performed in both water-wet and mixed-wet rocks. The objective of the experiments was to understand the impact of wettability and injection strategy, as well as generating reliable data for tuning a simulation model. A numerical model was developed and validated via experimental results under both wettability conditions, and then used to investigate the effect of a large number of parameters including; WAG starting time and slugsizes well as oil/gas IFT and wettability on the performance of different injection scenarios.
The results show that for water-wet systems, the highest oil recovery is achieved by SWAG (Simultaneous Water and Gas) and WAG injections and the poorest injection scheme is primary WF (water flood), whereas in the mixed-wet system, WAG and SWAG are the best and worst injection scenarios, respectively. In water-wet systems, the SWAG performance improved by increasing the ratio of gas to water while in mixed-wet systems, SWAG performance decreased by increasing gas to water ratio. Under water-wet conditions, better performance was achieved by smaller WAG slug sizes (higher number of WAG cycles) but for mixed-wet systems WAG performance decreased with increasing the number of the cycles. Our results also show that under near-miscible oil/gasconditions (IFT = 0.04 mN.m-1), the oil recovery by primary GF (Gas Flood) was much higher for water-wet systems compared to the mixed-wet conditions. Although the same trend has been observed for the immiscible condition (IFT = 9.4 mN.m-1), but under immiscible conditions the difference between the performance of GF for the two wettabilities(water-wet and mixed-wet) is not significant.For all oil/gas IFT values tested, WAG performance was found to be higher in mixed-wet systems compared to their water-wet counterparts, however, the effect of wettability was more pronounced in higher gas/oil IFT conditions. For both wettability conditions, starting WAG before water breakthrough of theprimary WF increased oil recovery.
Various techniques of Enhanced Oil Recovery (EOR) exist and amongst them water and gas injection are the most widely used. It has been shown that combining water and gas injection in a WAG (water alternating gas) scheme can result in additional oil recovery. Interest in WAG injection has increasingly grown in recent times with many reservoirs around the world now under WAG injection.
Numerical simulation of WAG requires reliable three-phase relative permeability and hysteresis data which are normally obtained from models available in commercial simulators. This paper utilizes core-flood experimental data from literature to investigate validity of these models.
The findings from this study provide evidence that different three-phase relative permeability models were found to behave differently giving varying recovery factors in a WAG simulation scheme. While the effect of irreversible hysteresis was studied, it was observed here that imbibition (stage I) and drainage (stage II) processes gave results that deviated from conventional hysteresis. Simulations were run with and without hysteresis for different three phase relative permeability models with different effects observed for the recovery factor.
The results of this work show that a good understanding of the three phase relative permeability model in use is very important for a more robust reservoir simulation model. Also, the effect of irreversible hysteresis in WAG injection should be adequately modelled in order to obtain reliable results. Lastly, the results reveal the importance of optimum WAG ratio for maximizing oil recovery by preventing a gas tongue forming at the top of the reservoir and a water tongue forming at the bottom of the reservoir.
The paper presents compositional simulation studies of miscible water-alternating-gas (WAG) flooding in stratified reservoirs with respect to compositional variation with vertical depth and temperature. Two series of fluid system were selected from fifth and third SPE comparative study for Reservoir-A and Reservoir-B respectively. The Reservoir-A is an undersaturated black oil reservoir and has initial gas-oil ratio (GOR) of 557 scf/stb. Meanwhile Reservoir-B is near-critical oil reservoir with initial GOR of 3519 scf/stb. The minimum miscible pressure (MMP) variation with depth was calculated using equation of state in both reservoirs. In this study, temperature gradient sensitivity is ranging from 10 to 30 oF per 1000 ft for both active and passive thermal gradient.
The existence of thermal diffusion in WAG process is also discussed. It is investigated that active and passive thermal gradient will give opposite composition variation trend. In active temperature gradient, the amount of light components will increase and heavy components will opposite with respect to depth. Unlike active thermal gradient, the gravity isothermal and passive thermal gradients segregate the heavy components toward the bottom.
The initial oil in place (IOIP) varies due to compositional variation which is again due to gravity and thermal gradients. These issues should be even more obvious when we have oil reservoir with higher GOR or near-critical reservoir. In these particular reservoirs, the presence of gravity and passive thermal gradients will decrease IOIP calculation whereas both reservoirs will have less C7+ components than in basecase. Otherwise, considering thermal diffusion effect by applying active thermal gradients will increase IOIP.
Several parameters were also evaluated during WAG process in both reservoirs such as: various hydrocarbon injection gases, cyclic injection scheme, WAG cycle and ratio, and reservoir heterogeneities. Therefore the effect of compositional variation due to gravity and thermal gradients can be conclusively evaluated.
Immiscible WAG (IWAG) processes, although proven quite useful in maintaining pressure in low permeability reservoirs, has the inherent drawback of leaving high residual oil saturation (Sor) behind the flood front. Often, dependent on the reservoir characteristics, the oil volume which is left behind by a secondary IWAG process can be of significant value and requires investigating tertiary EOR processes that could economically produce it. This case study discusses the approach taken to mature an EOR opportunity in a giant onshore carbonate reservoir currently being developed with IWAG injection.
A plan was put in place to assess the suitability of prospective EOR processes in the subject reservoir. This commenced with a detailed PVT lab study which involved specially designed EOR tests such as swelling, slimtube, forward contact, backward contact, equiphase and asphaltene deposition. The experimental data was used to develop an equation of state model (EOS) that is able to describe the reservoir fluid behavior. Next, analytical methods were used to screen out the EOR processes found most promising. The EOR processes were screened based on the performance indicators estimated using classical reservoir engineering techniques, empirical methods, experience and judgment. The favourable results for the CO2 injection, both from the PVT experiments and the analytical screening led to the design of 1D coreflood experiments on composite cores at full reservoir conditions.
Comparison of the different displacement tests showed CO2-WAG to be highly efficient recovery mechanism with 93% of the HCPV recovery potential. The PVT experiments and the coreflood injection tests, within their experimental limitations provided recovery profiles and CO2 injection characteristics to validate model predictions on a microscopic scale, and thus enhanced confidence in full field development studies based on the underlying reservoir simulation models. The proposed CO2-EOR strategy will help reduce the Sor significantly and hence improve Ultimate Recovery (UR). A field pilot is being considered to evaluate the CO2 injection recovery process optimally.
Lawrence, John J. (ExxonMobil Upstream Research Co.) | Sahoo, Hemant (Exxon Mobil Corporation) | Teletzke, Gary F (ExxonMobil Upstream Research Co.) | Banfield, Jessica (ExxonMobil Canada) | Long, Jamie M. (ExxonMobil Canada) | Maccallum, Nicholas (ExxonMobil Canada) | Noseworthy, Ryan J. (ExxonMobil Canada) | James, Lesley A (Memorial University of Newfoundland)
The Hibernia oil field is located in the North Atlantic Ocean over 300 km from St. John's, Newfoundland. The field consists of numerous fault blocks undergoing conventional gas or water injection. The gas injection process is proving to be very efficient providing high recoveries in individual blocks. Expansion of gas injection through conventional development or EOR may potentially provide significant benefits if optimized correctly under a limited gas supply. The need to understand the relative benefits of gas injection into one block versus another has increased and necessitated a full gas utilization study. One EOR option being considered is water-alternating-gas (WAG) injection in some blocks.
The objective of the study is to establish a field-wide improved recovery plan based on integrated laboratory, reservoir simulation, pilot, gas supply, and infrastructure studies. This paper will describe the integrated study plan and current progress.
The Gas Utilization Optimization Project entails three broad phases: 1) Study Phase; 2) WAG Pilot Execution; and 3) Field-Wide EOR Development. The primary focus at this point is the Study Phase, which will include laboratory studies, reservoir simulation studies, pilot engineering studies, and gas supply and infrastructure assessment.
The laboratory studies are being performed to develop a better understanding of PVT, EOR, and SCAL as it applies to the WAG pilot and field-wide development. The reservoir simulation studies provide a basis for the design of the EOR pilot and the field-wide development plan. Pilot engineering must be performed to ensure the pilot will provide the information necessary to make business decisions on future development. Assessing gas supply and infrastructure is essential to understanding gas availability, value, and opportunities for enhancement. This phase is particularly important for remote locations where external gas supplies are limited.
This study provides a template for obtaining and integrating information and data necessary to design, evaluate, and implement a gas injection project for improved oil recovery.
Mohd Anuar, Siti Mardhiah (Universiti Teknologi Malaysia) | Jaafar, Mohd Zaidi (Universiti Teknologi Malaysia) | Wan Sulaiman, Wan Rosli (Universiti Teknologi Malaysia) | Ismail, Abdul Razak (Universiti Teknologi Malaysia)
Spontaneous potential (SP) is commonly measured during reservoir characterization. SP signals are also generated during hydrocarbon production due to the streaming potential occurrence. Measurement of SP could be used to detect and monitor water encroaching on a well. SP signals could also be monitored during production, with pressure support provided by water alternate gas (WAG) process. The objectives of this study are to quantify the magnitude of the SP signal during production by WAG injection and to investigate the possibility of using SP measurements to monitor the sweep efficiency.
Measurement of streaming potential has been previously proposed to detect the water encroachment towards a production well. The peak of the signal corresponds to the waterfront where there is a change of saturation from ionic water to non-polar hydrocarbon. Similar trend is predicted in the case of WAG where we have several interfaces between the injected water and the injected gas.
The results indicate that the magnitude of the SP generated in hydrocarbon reservoir during WAG process can be large and peaks at the location of the moving water front. Gas, which can be assumed to be non-polar, exhibit no electrokinetic effect. These observations suggest that WAG displacement process can be monitored indirectly from the signal acquired. Water or gas override can be detected and controlled if wells were equipped with inflow-control valves. As a conclusion, the SP measurement is a promising method to monitor the effectiveness of a WAG process.
This study is significant because monitoring the progress of water and gas in a WAG process is key in the effectiveness of this enhanced oil recovery method. Measurement of the streaming potential provides another method besides using tracers to monitor the WAG profile. Better monitoring will lead to more efficient displacement and great benefits in term of economy and environment.
Malaysia‘s oil predominantly comes from offshore fields. Malay Basin located to the East of Peninsular Malaysia contains most of the country's oil reserves. In the maturing oil fields of Malaysia, EOR options are being field-tested for enhancing and prolonging production. A Water Alternating Gas (WAG) pilot was implemented in the Dulang Field S3 Block during 2002-6. The S3 Block contained six wells (three producers and three injection wells) in two reservoirs namely E12/13 and
This pilot project was the first EOR pilot in Malaysia. The main objectives of the pilot project were to design and develop the EOR scheme, and to evaluate the feasibility of WAG injection to maximize the oil recovery from this and other similar oil fields. A comprehensive monitoring was undertaken to assist in evaluation of pilot performance. Identification of optimal operating conditions, Dulang field-specific screening criteria and success indicators were perceived to be germane
for future WAG implementation.
Oil bearing sands of the Dulang field were deposited under fluvial or near shore environments as parts of sand-shale sequences. These strata were subsequently folded and faulted, resulting in discrete `compartments` with uncertain flow continuity across various faults. Due to existence of numerous major as well as, minor faults and thinness of shale layers at certain places, the critical considerations for EOR were a) confinement of the injected fluids within individual compartments,
and b) flow continuity between different injector and producer wells. It was therefore decided to use different water and gas phase tracers at each of the three injection wells within the S3 block. The data gathered were used for assessing internal communication, flow parameters and inter-well reservoir heterogeneity such as high permeability streaks. This paper discusses details of the tracer program and significant responses observed during the pilot implementation.
Water alternating gas injection (WAG) is normally employed to improve the volumetric sweep efficiency of miscible flooding processes. Literature search indicated a number of numerical studies investigated the effect of flooding rate, gravity forces, slug size, and heterogeneity on WAG processes performance. However there are very few numerical and experimental studies conducted on the effect of wettability on the efficiency of WAG processes. This work examines how to optimize WAG processes for carbon dioxide (CO2) floods above the minimum miscibility pressure (MMP) in both oil-wet and water-wet reservoirs. Stream tube simulation was used to assess the effects of WAG ratio, system wettability, flood pattern, solvent injection rate, project timing, and reservoir heterogeneity on the sweep efficiency and overall all recovery efficiency for oil-wet and water wet reservoirs. A series of secondary miscible carbon dioxide WAG displacement runs were performed employing WAG ratio's of 1:1, 2:1, 1:2, 3:1, 1:3 and straight carbon dioxide.
The main conclusions of this research show that system wettability has a significant impact on the optimization of WAG ratio, solvent injection rate, project timing, and flooding pattern selection.
The complex physics of the displacement processes involved in three-phase flow in porous media in the tertiary oil recovery processes is yet to be understood. Three phase relative permeability are usually calculated from two phase experimental data due to the complexity of three phase measurements and its duration, hence introducing uncertainty in the adopted models. Pore-scale laboratory studies have shown strong irreversibility in the relative permeability among the successive drainage and imbibitions cycles and its path dependency, which is called hysteresis. Understanding this phenomenon and its effect play a major role in evaluation and success of any tertiary recovery processes such as WAG EOR. Several models have been proposed to predict this mechanism, three phase zone and predict the true residual oil saturation. To better evaluate and mitigate the risks involved, the impact of many parameters used in the current predictive tools and hysteresis models should be fully understood and investigated.
In this work relative permeability hysteresis, three phase region and various involved parameters affecting the hydrocarbon recovery have been investigated. A heterogeneous sector model supported with actual SCAL data were used for the purpose of this study. The results of the study and the adopted methodology have been later compared and verified with the actual real field performance data under the same processes.
Generally the results show significant difference in term of residual oil saturation whether or not a relative permeability hysteresis modeling is employed. The study also demonstrates the necessity of fine-tuning the hysteresis model parameters to the actual SCAL data to obtain more realistic parameters to be used in prediction phase. Reservoir heterogeneity play a major role in balancing the viscous and gravity forces as well as the three phase region size to achieve higher hydrocarbon recovery.
The "PF-A-I?? - an undersaturated oil reservoir located in Hungary- is more than 50 years old.
It was discovered in the late 1950' years and put in production in 1960. The reservoir produced by depletion, then by CO2 injection, by WAG injection, afterwards by water injection and finally by "depletion?? again.
The case study shows all production stages in detail - the most important data, what were the results of different type of injections, how saturations, pressure, recovery factor changed followed by the comparison of planned injection and production rates with facts by diagrams and maps.
It shows why the CO2 injection was more important than the experts thought and which type of injection was the most effective and gave the most extra oil.