Farajzadeh, Rouhollah (Shell Intl. E&P BV) | Ameri, Amin (Delft University of Technology) | Faber, Marinus J. (Shell Intl. E&P BV) | Van Batenburg, Diederik W (Shell Exploration & Production) | Boersma, Diederik Michiel (Shell Intl. E&P BV) | Bruining, J. Hans (Delft University of Technology)
Alkali Surfactant Polymer (ASP) flooding has traditionally been considered in tertiary mode, i.e., after a reservoir has been sufficiently water flooded. In screening studies experiments are usually conducted under two-phase flow conditions, i.e., in the absence of a gas phase in the rock.
In practice, oil reservoirs might contain some gas. In areas in the world, where gas flaring is not allowed and an infrastructure for gas transportation is not present, re-injection of produced gas is a common practice. Moreover, when the reservoir is depressurized below bubble point a gas phase will be created.
To the best of our knowledge, there are no data in the literature concerning the influence of in-situ gas phase (continuous or trapped) on the performance of ASP floods. The main objective of this paper is to evaluate how the presence of a free (non-dissolved) gas phase affects ASP flood performance. To this end, several experiments were carried out to evaluate different conditions, where free gas was present, either flowing or trapped.
We found that the ultimate residual oil saturation in most experiments is similar to the case without gas. When free gas is present in the porous medium, the oil-bank production occurs earlier, because a large fraction of the gas remains trapped and therefore the "effective?? pore volume for liquid flow is reduced. When the gas and the ASP solution are co-injected, the oil is mostly produced in emulsion form as gas enhances mixing of the in-situ fluids. Trapped gas could lead to an efficient oil recovery, depending on the amount of trapped gas: the lower the trapped gas saturation the better the oil recovery.
Castro, Ruben Hernan (ECOPETROL, S.A.) | Maya, Gustavo Adolfo (Ecopetrol SA) | Sandoval, Jorge (Ecopetrol SA) | Leon, Juan Manuel (Ecopetrol SA) | Zapata, Jose Francisco (Ecopetrol SA) | Lobo, Adriano (Ecopetrol SA) | Villadiego, Darwin Oswaldo (ECOPETROL, S.A.) | Perdomo, Luis Carlos (ECOPETROL, S.A.) | Cabrera, Fernando Ariel (TIORCO, Inc.) | Izadi, Mehdi (TIORCO, Inc.) | Romero, Jorge Luis (TIORCO Inc) | Norman, Charles (TIORCO, Inc.) | Manrique, Eduardo Jose (TIORCO, Inc.)
Dina Cretaceous Field is located in the Upper Magdalena Valley (UMV) Basin, Colombia. Dina Field operated by ECOPETROL S.A. (discovered, 1969) started peripheral water in 1985. Based on high water cuts (96%) and recovery factors of 32%, comprehensive enhanced oil recovery (EOR), screening evaluation began late 2009, identified Colloidal Dispersion Gel (CDG) as an optimum EOR method for the field.
This paper summarizes Dina CDG project from the laboratory to the field evaluation. Laboratory studies include basic fluid/fluid evaluation, static adsorption, CDG formulations, slimtube, and coreflood tests. Pilot area selection was based on a comprehensive reservoir and injection/production data analysis, water management, well integrity, among other factors. Pilot design was based on detailed numerical simulations using sector and full field models. CDG pilot design also considered water handling limitations and potential injectivity constraints due to the narrow margin of maximum injection and reservoir pressures, combined with low reservoir permeability (50 to 200 mD).
Peripheral CDG pilot included one injector and three producers. CDG injection began in June 2011 and as of September 2012, approximately 437,000 bbl of CDG have been injected (5% of pilot PV). CDG injection strategy considered a fix polymer concentration of 400 ppm and a variable polymer/crosslinker ratio ranging from 40:1 to 80:1; to control maximum injection pressure. Field results showed an important increase in oil recoveries (oil productivity up to 300%) and reduction of water cut decrease (10%). After 16 months, no polymer had been produced in offset producers. Main operating challenges experienced during the pilot project included; the improvement in water quality and its impact on CDG injectivity which will also be described.
This study provides guidance to successfully design, implement, and evaluate CDG pilot projects and other potential chemical EOR technologies in waterflooded reservoirs. Lessons learned during pilot testing contributed to defining pilot expansion strategies supported by an integrated decision-risk management approach.
Enhanced Oil Recovery (EOR) has been touted as the Holy Grail for achieving the highest possible recovery factor. This technology is fairly matured in land based development, with older fields in Bakersfield and Indonesia achieving up to 90% recovery factors. However, EOR considerations take on a whole new dimension in an offshore environment. Astronomical rig rates and escalating operational costs have deterred operators from pursuing ambitious offshore EOR programs.
Most EOR pre-development studies are focused on the reservoir; in particular altering relative permeabilities, reducing residual hydrocarbon saturations, and improving sweep efficiencies. But with up to 40% of slated huge EOR capital development cost earmarked for well construction, more technical focus should be emphasized on well architecture.
This paper details the well architecture work done on several Malaysian fields scheduled for EOR redevelopment. A workflow featuring the various design and operational considerations is explained. Well architecture is composed of two main components: Trajectory and completions functionality. Malaysia's portfolio of complex reservoirs requires EOR development to be done through a creative lens of complex trajectories and multilateral wells. Marginal economics have precluded the practicality of conventional well construction.
A key enabler in cost efficient EOR redevelopment is advanced completions, namely remote downhole flow control and monitoring. In order to achieve incremental production beyond secondary recovery, reservoir conformance is of critical importance. Remote real time monitoring will allow decisions to be made accurately in a timely manner. Downhole flow control permits purposeful manipulation of injection and production streams. Proper installations of advanced completions will also reduce future intervention and operational costs.
Advanced well architecture however, also comes with a whole range of operational and installation risks. But these can be mitigated with proper planning and coordination with all parties involved.
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.
Uribe Hidalgo, Carlos Andres (Universidad Industrial de Santander) | Munoz Navarro, Samuel Fernando (Universidad Industrial de Santander) | Oliveros Gomez, Luis Roberto (Universidad Industrial de Santander) | Naranjo Suarez, Carlos Eduardo (Ecopetrol S.A)
In order to determine the best operating scheme, and taking into account the increase in demand for oil and the need of increasing the recovery of existing fields, enhanced recovery techniques are an alternative to the oil industry.
In Colombia, the stratified deposits of heavy oil have become the focus of oil exploration with EOR methods, including the one which is conceptually evaluated in this paper. However, the production of these fields has been restricted to strata having considerable thickness, forgetting about certain amounts of hydrocarbons from thin strata, representing significant potential for increasing production and reserves.
In search of the best alternative for extracting heavy oil reserves are contained in thin strata reservoir, this paper shows the technical and financial evaluation of applying cyclic steam injection using horizontal wells in these fields, using the injectivity and the benefit of the location Horizontal wells, and viscosity reductions product with steam heating. To carry out this process, It was evaluated the effect of each operational and reservoir parameters. Subsequently, due to the uncertainty of the distribution of steam in the reservoir and the importance of heterogeneities in this effect, the numerical simulation was performed with homogeneous and heterogeneous models, comparing productive behavior of each stage, to determine the best model to use in optimizing operational parameters.
Once the best scenario was determined it was performed a sensitivity and process optimization, seeking operating conditions that showed the best results with cyclic steam injection in horizontal wells, for further financial analysis that would provide a comprehensive feasibility study .
Advantages of CO2 in enhanced oil recovery for Iranian oil reservoirs offers a unique opportunity to boost incremental oil recovery and reducing emissions of greenhouse gas through geological sequestration. Moreover, because of the dominant role
of gravity force in gas injection process in fractured reservoirs, and also relatively low minimum miscibility pressure (MMP) of CO2, therefore, miscible CO2 injection with Gas Oil Gravity Drainage (GOGD) mechanism can be considered as an
efficient method in most carbonate reservoirs.
In this paper, different production strategies such as vertical and horizontal immiscible and miscible gas injection were applied to find the optimum EOR method in one of the under-saturated Iranian fractured reservoirs.
To aim this goal, a study with simulation approach was conducted while the effect of gravity drainage on recovery was investigated besides other mechanisms. A complete analysis of phase behavior, PVT properties of reservoir fluid and CO2
mixture was done. These data were applied in designing of the slim tube and full field simulation model. A fully compositional reservoir simulator was employed to understand the reservoir characteristics, also, verifying the suitability of CO2 injection.
Material balance analysis indicated the original oil in place (OOIP) is about 910 million STB with a relatively strong water support. The maximum oil production of 60,000 STB/D was assumed in all simulation cases. Reservoir simulation results
revealed that additional oil recovery could be obtained from this fractured reservoir by miscible gas injection, while gravity drainage was the main displacement mechanism. In case of vertical well production, the model predicted an increase in oil
recovery about 24 and 28% OOIP for immiscible and miscible CO2 injection respectively. Considering horizontal producers and gravity drainage as the dominant production mechanism, immiscible and miscible gas injection will enhance oil
production more than 28 and 36% OOIP respectively.
The goal of an oil field development project is to accelerate the hydrocarbon production and maximize the recovery at a lowest cost. For a thin oil rim reservoir with a large gas cap on top and a strong aquifer below, achieving such goal can be very challenging since recovery of both oil and gas shall be maximized. A successful project shall entail plan first to accelerate the oil production maximizing the oil recovery prior to the gas cap blow-down.
The maximum oil recovery factor achievable in thin oil rim reservoirs was evaluated for a Malaysian thin oil rim reservoir based on dynamic flow properties. The force balance between the gas cap expansion, aquifer expansion and viscous withdrawal was demonstrated by showing the model simulated water-oil and gas-oil contact movement. The understanding of the force balance progressively guided the field development project team to selectively re-activate some of the idle wells, to selectively place new additional infill horizontal wells, and to plan selective water and gas-cap gas injection in key reservoir sectors.
In this paper, the reservoir simulation study on simultaneous up-dip water and down-dip gas injection was reported. The downdip gas injection, injecting gas at and close to water/oil contact, was found to be able to impede bottom aquifer advancement, improve sweep and further enhance the thin oil-rim oil recovery. The gravity assisted injection technique could become a cost effective alternate for IWAG particularly for remaining oil rim which can be less than 10 m after the successful primary and secondary production.
Garmeh, Gholamreza (TIORCO, Inc.) | Izadi, Mehdi (TIORCO) | Salehi, Mehdi (TIORCO, Inc.) | Romero, Jorge Luis (TIORCO LLC) | Thomas, Charles Philip (TIORCO, Inc.) | Manrique, Eduardo Jose (TIORCO a Nalco Stepan Company)
A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer, which is an expandable sub-micron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods.
This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed.
Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief zone permeability diverting flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depends on the thief zone temperature, vertical to horizontal permeability ratio (Kv/Kh), thief zone vertical location, injection concentration and slug size, oil viscosity, chemical adsorption, and its reversibility, among others. For high flow capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Low Kv/Kh (< 0.1) and high permeability contrast generally shows faster incremental recoveries than high Kv/Kh with strong water segregation reservoirs.
The presented workflow is currently used to perform in-depth conformance treatment designs in on-shore and off-shore fields and can be used as a reference tool to evaluate benefits of the thermally active polymer in waterflooded oil reservoirs.
A common problem in waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Several approaches have been proposed to reduce water channeling and high water cuts. Mechanical isolation, the use of selective advanced completions (e.g., sliding sleeves), and especially polymer gels to modify injection profiles or as water shut-off strategies are some of the most common approaches used to manage water injection projects. However, the use of thermally active polymer for in-depth conformance strategies has been gaining more interest in recent years.
Fletcher et al. (1992) was one of the first published papers proposing the use of deep diverting gels (DDG) to improve waterflood sweep efficiencies. This study reported slimtube tests using systems of polyacrylamide polymer and aluminum citrate and also conceptual simulations using the BPOPE model, a modified version of UTChem, originally developed at the University of Texas. In 1996, BP sponsored an industry academic seminar that later became a joint (BP, ChevronTexaco and Nalco) research project known as BrightWater® (Frampton et al. 2004; Pritchett et al. 2003).
Recent laboratory and mechanistic modeling studies have demonstrated that CO2-foam has the potential to recover additional oil in fractured water flooded chalk rock with low matrix permeability. The CO2-foam processes were carried out in short core plugs by injecting pre-formed foam at 340 bar and 55oC. The fractured model was represented by core plug with a 0.3 cm diameter hole drilled though the centre, and packed with monodispersed glass beads. Calculated mobilities also indicated that CO2-foam is highly effective in decreasing the mobility of CO2 and increasing the apparent viscosity of CO2 in fractured chalk rock.
In this work, mechanistic simulation studies based on history-matched foam models tuned to laboratory data are used to investigate the effect of the strength of pre-formed foam and the role of gravity forces on oil recovery in long fractured chalk models. Pre-formed foam was injected either horizontally or vertically (from the bottom) at 340 bar and 55oC. Pure CO2 injection was also injected in fractured chalk models and used as base cases. The foam qualities and water saturation were varied.
Results indicate that decreasing the foam quality increases the rate of oil production with both horizontal and vertical injection of pre-formed foam. However, the oil recovery efficiency with horizontal injection of pre-foamed foam was higher than with vertical injection. The simulation results show that molecular diffusion is an important oil recovery mechanism in chalk fractured rock with low matrix permeability and should be taken into account, and that considerable gravity effect can affect the oil recovery in horizontal injection of pre-formed foam. The mechanistic models can be used to study CO2-foam processes in fractured chalk reservoirs with multiple fractures.
Ashrafi, Mohammad (Norwegian University of Science and Technology) | Souraki, Yaser (Norwegian University of Science and Technology) | Karimaie, Hassan (Norwegian University of Science and Technology) | Torsaeter, Ole (Norwegian University of Science and Technology) | Kleppe, Jon (Norwegian University of Science and Technology)
Bitumen resources constitute a high portion of the total world oil resources. The main recovery mechanism for these high viscous fluids is to reduce their viscosity by the application of heat, mostly by introducing steam.
Among different steam injection schemes, steam assisted gravity drainage (SAGD) has become the method of choice applicable to bitumen and oil sand reservoirs. In these extra heavy oil resources, the reservoir has almost no injectivity due to high oil viscosity, and therefore conventional steam flooding is hard to conduct. SAGD, however, reduces the viscosity of bitumen in place and the heated bitumen drains due to gravity forces towards the production well and is then being produced. Recently hybrid processes are attracting more attentions in the industry. These processes benefit from co-injection of a solvent together with steam. The solvent can diffuse into the bitumen and make it even lighter by reducing the viscosity.
Our simulation study is based on the experimental work done by Chung (1988) and the simulation model of this experiment by Chow (1993). Chung's physical experiment was a 2-D model to simulate SAGD experiment in laboratory. The Chung's experiment was done with Cold Lake crude oil. A reservoir simulation model was built using a numerical thermal reservoir simulator. The model was then tested and validated with Chung's physical model. Having a valid model, sensitivity analysis was run to examine the effect of different simulation parameters on recovery and steam oil ratio.
The sensitivity parameters tested are steam temperature and quality, the porosity of the model, different well placement schemes, and the effect of shale barrier. Different steam temperatures and qualities were examined. The best injection condition was found to be 130 °C and 90% quality, beyond which no increased recovery was achieved. Different injector and producer placements were tested. Placing injector and producer diagonally in the model showed the best horizontal sweep efficiency in the laboratory model. Horizontal shale barrier had a dramatic negative effect on the oil recovery. Vertical shale, however, had a smaller effect. This is because in horizontal case the steam chamber cannot reach to the top layers. Porosity was found to be inversely proportional to the oil recovery and steam oil ratio. Results showed that solvent can help to improve oil recovery and steam-oil ratio. In addition most of the injected solvent could be recovered from production stream. Sensitivity analyses on solvent type and concentration indicated significant effects on performance of process. Among the solvents used in this study, hexane showed the best recovery performance.