Sahin, Secaeddin (Turkish Petroleum Corporation) | Kalfa, Ulker (Turkish Petroleum Corporation) | Uysal, Serkan (Turkish Petroleum Corporation - Library) | Kilic, Harun (Turkish Petroleum Corporation) | Lahna, Hakki (Turkish Petroleum Corporation - Library)
With initial oil in place of 1.85 billion barrels, Turkey’s largest oil field Bati Raman was discovered and put on stream in 1961. The field attained a primary recovery of lower than 2% due to the poor quality of the rock and fluid properties of the reservoir and a low energy drive mechanism.Immiscible carbondioxide (CO2) flooding project of Bati Raman commenced in 1986, and it has been successfully implemented for over the period of quarter century to drive up oil rate of the field. Oil production, which was only 1.500 STBD prior to the EOR project, hasreached to 14.000 STBD level by increasing 8-9 times at the peak performance period, showing a declining trend thereafter. The project is still active; the
on-going application in the field has been a unique and successful process. It added significant value to the field and in the long run it turned out to be anexcellent application showing a 3-4 times increment in the recovery factor. Nevertheless, the amount of CO2 required for one extra barrel of oil has tendency to increase and, it is a fact that the CO2 injection will soon complete its mission remaining a great deal of oil in the reservoir. Therefore, there is a great incentive to implement another effective enhanced recovery process in the field to drain this remaining oil. Now the field is under consideration for another marginal and unique application. No analogous worldwide is yet known: Steam Injection Pilot in already CO2 flooded Deep-Heavy Oil Fractured Carbonate reservoir. There are a few similar applications, but their depths are incomparably shallower than the Bati Raman field. A steam injection pilot with two injectors, one observer, and eleven producers at the crest was
commenced in September 2012. The purpose is to heat and pressure up the reservoir from the top and produce oil from the neighboring producers. This paper documents design, implementation and early operating results of this pilot project being conducted in the Bati Raman field.
The advantages of using the low salinity water injection (LSWI) technique to improve oil recovery in carbonates are well pronounced; however, the mechanism behind it is still ambiguous. This paper uses geochemical modeling to investigate the main mechanism of low salinity water injection (LSWI) in carbonate oil reservoirs. The geochemical modeling was performed using two geochemical simulators (UTCHEM and PHREEQC).
New geochemical flow and transport simulations show that anhydrite dissolution may contribute to wettability alteration by LSWI, but is not the main contributor. These simulations also show that the change in pH and the resulting change in surface charge expand the electrical double layer (EDL) which in turn alters the wettability and improves oil recovery. The emphasis in the literature is on the effect of pH causing in-situ generation of surfactants, whereas in this study the effect of pH on the surface charge is emphasized.
This study shows that the results of LSWI in carbonate rocks can be best explained as wettability alteration due to the change in surface charge as opposed to anhydrite dissolution. The improvement in oil recovery by LSWI in carbonates also depends on temperature, pressure, mineralogy, oil type, initial rock wettability state, and injected water composition, so the results in other carbonates might vary.
Magnus tertiary miscible gas injection started in 2002 through a WAG scheme yielding 18 mmstb of incremental oil to date at a very high net efficiency of 3.5 mscf/stb. Pore scale efficiency is very good with 8% Sorm based on core flood data. Areal and vertical gas sweep efficiency is sub-optimal based on 4D seismic and PLT data. This paper focuses on studies carried out to explore possibilities to improve sweep efficiency and the resulting pattern optimization programme in the field.
Magnus Sandstone Member (MSM) consists of a number of stacked turbidite sand lobes separated by intra-formational shales. The WAG scheme has been managed by considering MSM as a single reservoir unit. As the patterns have matured, it has become apparent that the scheme could be optimized by further vertical separation of the reservoir units. Key surveillance data such as 4D seismic monitoring gas movement, PLTs, well performance and open hole saturation logs have been coupled with simulation to explore options for sweep improvement. These options involve changing sweep direction by means of adding new perforations and shutting off zones, complete reversal of the patterns – i.e. converting producers to injectors and vice versa, and use of chemicals for flood diversion.
Evaluation of multiple options resulted in a phased WAG optimization programme of which the first phase is being proposed for execution in 2014. A behind flood front core is planned in 2015, which is expected to help calibrate the optimization programme by quantifying Sorm and the degree of vertical sweep achieved in the field. Relatively low cost options were identified to improve the sweep as opposed to drilling new wells. Integration with the operations team was the key in creating a business case for pattern optimization on a 30-yrs old, bed space constrained platform.
The workflow of this study and the learnings are applicable to mature patterns in any WAG scheme. Optimizing the WAG patterns enables more efficient use of the available gas, which -given that cost of gas is a significant component of any gas injection project- makes this more commercially viable and cost effective tertiary recovery option.
Puerto, Maura C. (Rice University) | Hirasaki, George J. (Rice University) | Miller, Clarence A. (Rice University) | Reznik, Carmen (Shell Global Solutions) | Dubey, Sheila (Shell Global Solutions) | Barnes, Julian R. (Shell Global Solutions) | vanKuijk, Sjoerd (Shell Global Solutions)
The effect of hardness, Ca++ and Mg++, was investigated on equilibrium phase behavior of alcohol-free systems made with blends of Alcohol Propoxy Sulfates and an Internal Olefin Sulfonate. Aqueous surfactant solutions and systems with water-to-oil ratio ~1 were studied. Experiments were performed at ~25°C and 50°C, the latter below the thermal stability limit of APSs. Hard brines tested were synthetic Sea Water, and 2*SW and 3*SW, brines having double and triple all ion concentrations in SW. Also tested were NaCl-only brines of the same ionic strength as the hard brines. The oil was n-octane, which has frequently produced optimal surfactant systems close to those for crude oils of interest.
This work applies to surfactant and is useful for surfactant-polymer floods.
Optimal blends of four APS surfactants with IOS15-18 formed microemulsions of high oil solubilization suitable for EOR applications at 25°C and 50°C. However, oil-free aqueous solutions of optimal APS/IOS15-18 blends exhibited cloudiness and/or precipitation, making them unsuitable for injection at 25°C and 50°C in 2*SW, 3*SW, and corresponding NaCl solutions. This behavior results from substantial content in optimal blends of IOS15-18, which has poor tolerance to high salinities and hardness. In SW the aqueous solution of the optimal blend of Branched alcohol67 PO7 sulfate and IOS15-18 was clear. A salinity map was prepared for this blend, which should be useful in selecting compositions for injection for processes where injection and reservoir salinities differ.
More options for alcohol-free processes in SW were obtained by blending Branched alcohol67 PO7 sulfate with other APSs and Alcohol Ethoxy Sulfates. Several such blends formed microemulsions with high octane solubilization and clear aqueous solutions in SW at 25°C near optimal conditions. An APS/AES blend was found to form suitable microemulsions in SW with a crude oil at its reservoir temperature near 50°C.
The results illustrate advantages of using alkoxylated sulfates at low and intermediate temperatures and salinities. Blends of alkoxylated sulfates merit further study for EOR processes with hard brines because they may facilitate obtaining clear aqueous solutions for injection.
Millimeter-sized superabsorbent polymer (SAP) or called preformed particle gel (PPG) are gaining attention and popularity for use in conformance-improvement treatments. The strength of PPGs is important to their performance as a conformance control agent. Measuring conventional gel strength has been always accomplished by applying load to single isolated samples with certain geometry. However, determining the strength of sugar-like PPG particles with irregular shapes is a challenging task. Previous publications showed the use of different methods to evaluate swollen PPG strength. However, those methods are either costly or inaccurate. We designed an apparatus that can be used to fast and accurately evaluate PPG strength.
We present PPG strength evaluation results using a simplified experimental apparatus. It composed of a positive displacement hand pump and a specially-designed piston accumulator. The top cap of the accumulator has a hole connected to the pump by tubing and fittings. The bottom cap is a stainless steel screen plate with multiple holes. The size of the holes represents the pore throat size. During the experiments, we put swelling PPG on top of the screen plate and below the piston, gradually increasing the pressure to push the piston until particles pass through the holes. The maximum pressure that pushes particles out of holes will be the threshold pressure of a particle moving through a pore throat. This pressure is representing the strength of the gel and can be used in PPG characterization.
We observed that PPG are prone to stiffen with brine concentration increase which caused an increase in threshold pressure. We also witnessed that PPG injection pressure depends chiefly on the swelling ratio and the screen hole size. However, the injection pressure does not increase significantly with injection rates. Behavior consistent with the real-time injection pressure and injection rate change observed during PPG treatments in oilfields. We also found that the gel threshold pressure have an excellent correlation with its elastics module which is measured by rheometer.
This method can provide a simple fast practical technique to quantitatively evaluate particle gel strength in laboratory and on site during PPG treatment process.
Shale gas reservoirs have been proposed as feasible choices of location for injection of CO2 and/or N2 because this method could enhance recovery of natural gas resources, while at the same time sequester CO2 underground. In this paper, a fully coupled multi-component multi-continuum compositional simulator which incorporates several transport/storage mechanisms is developed. To accurately capture physics behind the transport process in shale nanopores, Kundsen diffusion and gas slippage are included in the flow model. An extended Langmuir isotherm is used to describe the adsorption/desorption behavior of different gas components and the displacement process of methane as free gas. Pressure-dependent permeability (due to rock deformation) of natural fractures induced by hydraulic fracturing is also considered in the simulator.
In addition, modeling of complex fracture networks is very crucial for simulating production of shale gas reservoirs because there exists various scales of fractures with multiple orientations after the fracturing treatment for horizontal well. In this work, a hierarchical approach which integrates EDFM with dual-continuum concept is adopted. The hybrid model includes three domains: matrix, major hydraulic fractures and large-scale natural fractures (described by EDFM), and micro-fractures in SRV region which are modeled by dual-continuum approach. Embedded Discrete Fractures Model (EDFM) is an efficient approach for explicitly simulating large-scale fractures in Cartesian grid instead of complicated unstructured grid. Moreover, a nested-grid refinement method is used to capture the fluids transfer from matrix to fractures.
Fully implicit scheme is applied for discretizing fluid equations, and the corresponding Jacobian matrix is evaluated by Automatic Differentiation with Expression Templates Library (ADETL). The AD-Library framework allows wide flexibility in the choice of variable sets and provides generic representations of discretized expressions for gridblocks. Several simulations and sensitivity analysis are performed with the developed research code for determining the key factors affecting shale gas recovery. Modeling studies indicate that the properties of fracture networks could greatly influence methane production. Different injection strategies including huff-n-puff process are also evaluated for optimizing production of multi-fractured horizontal well. Results show that CO2/N2 injection can be an effective approach with great application potential for enhancing shale gas recovery.
Dang, Cuong T.Q. (University of Calgary) | Nghiem, Long X. (Computer Modelling Group Ltd.) | Chen, Zhangxin (University of Calgary) | Nguyen, Ngoc T.B. (University of Calgary) | Nguyen, Quoc P. (University of Texas At Austin)
This paper proposes a novel concept of low salinity water-alternating-CO2 (CO2 LSWAG) injection under CO2 miscible displacement conditions. While LSW is an emerging EOR method based on modification of wettability and intrinsic permeability, WAG is a proven method for improving gas flooding performance by controlling the gas mobility. Therefore LSWAG injection promotes the synergy of the mechanisms underlying these methods (i.e. ion-exchange, wettability alteration, and CO2 dispersion) that further enhances oil recovery and overcomes the late production problem frequently encountered in the conventional WAG. These features are demonstrated in this work based on a field case study.
To investigate the advantages of CO2 LSWAG, a comprehensive ion exchange model associated with geochemical processes has been developed and coupled to the multi-phase multi-component flow equations in an equation-of-state compositional simulator. Laboratory core flood simulations of different CO2 LSWAG schemes are conducted to understand the solubility of CO2 in brine, dissolution of carbonate minerals, ion exchange, and wettability alteration. CO2 LSWAG performance is then evaluated on a field scale through an innovative workflow from geological modeling, multi-phase multi component flow modeling to process optimization. The simulation results indicate that CO2 LSWAG has the highest oil recovery compared to conventional high salinity waterflood, high salinity WAG injection, and low salinity waterflood. A number of geological realizations are generated to assess the geological uncertainties effect, in particular clay distribution uncertainties, on CO2 LSWAG efficiency. Finally, LSWAG injection strategies is optimized by identifying key important factors such as injected water salinity, WAG ratio, CO2 and water slug sizes.
This model was built in a robust reservoir simulator, it serves as a powerful tool for screening, design, optimization, and uncertainty assessment of process performance from laboratory to and field scales.
Significance of Subject Matter
CO2 LSWAG is a promising EOR technique as it not only combines the benefits of gas and low salinity water floods but also promotes the synergy between these processes through the interactions between geochemical reactions associated with CO2 injection, ion exchange process, and wettability alteration. This paper demonstrates the merits of this process through modeling, optimization and uncertainty assessment.
CO2 flooding often results in poor sweep efficiency due to the high mobility ratio caused by its low viscosity. To mitigate this problem, the alternate injection of water and CO2 slugs, known as the water-alternating-gas process (WAG), is widely applied. Recently, numerical simulation and core flood experiments indicate that the use of chemicals in the water slug may improve mobility control during WAG, thus increasing the ultimate recovery and reducing the requirements for newly purchased or recycled CO2. Therefore, the study of the stability of common polymers used for EOR applications in CO2 saturated environments becomes necessary to address the technical and economic feasibility of this process.
In this paper, we report the results of two commonly applied EOR polymers, a co-polymer of acrylamide and acrylate and a co-polymer of acrylamide and ATBS (Acrylamide tert-Butyl Sulfonate). To establish a base line for comparison, parallel experiments were conducted in two different oxygen free environments: one with CO2 and the other with nitrogen. Samples were hydrated and aged at reservoir temperature over 300 days. To isolate the effect of CO2, polymer thermal and chemical degradation were reduced by stripping out dissolved oxygen and decreasing divalent cation concentration from the water prior to polymer hydration. Polymer samples were removed at different times and their viscosity was measured as a function of shear rate and fitted to a power law model. The ability of the polymer solutions to retain their original viscosity over time was used to quantify polymer degradation.
The results of this work show that CO2 impacts polymer stability, causing further degradation in both polymers tested. The co-polymer of acrylamide and ATBS exhibited higher resistance to CO2 degradation as it was able to retain 94 % of its original viscosity, compared with the co-polymer of acrylamide and acrylate which only retained 56 %. Factors as chemical degradation, hydrolysis and pH, that also affected the behavior of viscosity over time are addressed. We conclude that commercial polymers can be used during chemically assisted CO2 WAG when low divalent cation water is used at a reservoir temperature of 122 F.
Cyclic gas injection is considered as an effective and quick responding recovery process that has been widely used in the worldwide. Studies showed that cyclic gas injection combined with modern technologies such as horizontal well drilling and hydraulic fracturing has achieved promising results in low permeability formation. In this paper, the cyclic gas injection technique was introduced for improving oil recovery in stimulated fractured shale oil reservoirs. The biggest challenge for gas injection projects is the availability of injection gas which makes the economic viability of such gas EOR projects problematic. Different components of injection gas scenarios such as lean gas, enriched gas and CO2 were included in the simulation in order to analyze the EOR mechanisms of vaporizing, condensing or a combined condensing/vaporizing process. The effect of diffusion on the recovery mechanisms by cyclic gas injection in fractured shale oil reservoirs was discussed.
Our simulation results indicate that the stimulated natural fractures are critical to enhancing oil recovery and well productivity performance in shale oil reservoirs. Since the interaction of the induced hydraulic fractures with pre-existing natural fractures and fissures makes the hydraulically fractured reservoir modeling very challenging in shale oil/gas reservoirs, we can use a dual-continuum model by making changes to the fracture permeability and intensity to attain a better characterization of the natural fractures. We conclude that cyclic gas injection in shale oil reservoirs employing hydraulically stimulated fractures is feasible to improve substantial amounts of oil production than primary production.
Screening is considered the first step in evaluating potential Enhanced oil recovery (EOR) techniques for candidate reservoirs, making it important to update the screening criteria as new technologies are developed. However, all recently published screening criteria regarding polymer flooding were based on data collected from the bi-annual EOR surveys of the Oil & Gas Journal. These data have quality problems that previous research has not addressed. In addition, the data have two limitations. Firstly, they do not include some important information for polymer flooding screening, such as formation water salinity, divalent concentration, polymer type and concentration. Secondly, the field data do not represent recent polymer technology developments because many new polymers are in the stage of lab evaluation and pilot testing. To overcome these data quality problems and limitations, a new dataset is necessary to establish for polymer flooding project design.
This paper describes the collection of 609 projects, including 481 field projects from the Oil & Gas Journal, 73 experimental laboratory projects and 55 pilot test projects recorded in the literature. To ensure the quality of the dataset before running any analyses, box plots and cross plots were used to identify data problems. After detecting outliers and deleting duplicate and severely inconsistent data records, both graphical and statistical methods were used to analyze and describe the results of the dataset. After data cleaning, the majority distribution of each parameter was shown using a histogram distribution, and the range of each parameter and some of its statistical values were presented using a box plot. New screening criteria are presented based on these statistics and the defined data parameters. The developed criteria were compared with previously published criteria, and their differences are explained. In addition of traditional parameters, the new dataset and criteria also some other information critical to the design of successful polymer flooding projects, such as the salinity and temperature range of three major types of polymers: hydrolyzed polyacrylamides (HPAM), biopolymer and hydrophobically associating polymers.