Reservoirs which produce under active water drive offer a significant uncertainty towards implementation of Chemical EOR processes. This paper describes a successful pilot testing of ASP process in a clastic reservoir which is operating under strong aquifer drive. The field has ~ 30 years of production history. The objective of the pilot was to understand response of ASP process in a mature reservoir, which is operating under active edge water drive. The build-up permeability of the reservoir is 2-8 Darcy with viscosity~ 50 cP. Salient key observations like production performance, incremental oil gain, polymer breakthrough etc. are discussed in this paper after completion of the pilot.
On the basis of laboratory study and simulation, ASP pilot was implemented in the field in 2010.The pilot was designed with single inverted five spot pattern and one observation well. The pilot envisaged injection of 0.3 pore volume (PV) Alkali-Surfactant-Polymer (ASP) slug, 0.3 PV graded polymer buffer followed by 0.4PV chase water. The pilot was meticulously monitored for production performance and breakthrough of chemicals. All the pilot producers have more than 20 years of production history. Base oil rate and water cut were fixed before start of the pilot, on the basis of test data which was used to monitor pilot performance. Interwell Tracer Test (IWTT) was conducted before starting of ASP injection so as to understand sweep in the pilot area. In addition, quality of injection water and chemical concentration in ASP slug was checked regularly to ensure best quality.
Significant response of the pilot was observed within 15 months of the start of the pilot which was published in 2012. This paper aims to describe the learning and conclusion after successful completion of the pilot. ~40-50% jump in oil rate was observed during the ASP injection period which sustained for 12-18 months. However preferential breakthrough of ASP slug in one of the producer impacted the incremental oil gain. The preferential breakthrough of polymer was due to presence of high permeability streaks which was rectified by profile modification job. In addition, strong aquifer movement was experienced during ASP injection which leads to rise in water cut of a pilot well. However, the pilot well was restored through water shutoff jobs. After completion of ASP and mobility buffer, a cumulative incremental oil ~28000 m3 was obtained. Cumulative incremental oil gain is in line with simulation studies prediction. 12-14% decrease in water cut was observed which sustained for ~ 6-18 months. Regular monitoring of produced fluid indicated breakthrough of polymer and alkali in 2-3 producers. During the pilot, produced fluid handling issues like tough emulsion formation, lift malfunctioning etc. was not observed. These collective observation indicated success of the ASP pilot project.
There are very few case histories of successful ASP pilot implementation are available, in which the reservoirs has been operating under active aquifer drive. Learning of this ASP project can be taken forward for expansion of ASP flood and also designing of ASP pilot/commercial projects for analogous reservoirs.
The objectives of the present study are to evaluate a zwitterionic surfactant for applicability in EOR. The surfactant was tested in terms of its salt tolerance, thermal stability, interfacial reduction capability, wettability alteration and resistance to adsorption. The effect of salinity and alkalinity was also tested on the above stated physico-chemical properties of the surfactant.
The salt tolerance of the surfactant was tested by testing for precipitation of surfactant solution with increasing salinity at 30 °C and 80 °C. The thermal stability of the surfactant was tested by TGA testing. The interfacial tension of the crude oil and surfactant solution with varying surfactant concentration, salinity and alkalinity was tested by spinning drop technique. The wettability alteration by surfactant solution was tested by measuring contact angle on an oil wet sample. The adsorption study was done by measuring the concentration of surfactant after its solution was exposed to adsorption on crushed rock sample.
The surfactant had salt tolerance of 20% salinity. The surfactant was found stable to 130 °C as per TGA curve. The interfacial tension (IFT) was reduced to ultralow value by surfactant solution for concentration at and above its critical micelle concentration. The presence of salt had minimal effect on the IFT reduction capability of the surfactant solution. Presence of alkali had synergetic effect on IFT reduction. The wettability of the oil wet sample was altered to preferentially water wet by surfactant. The loss of surfactant due to adsorption was found to be within recommenced range for applicability in EOR. These excellent physico-chemical properties of the zwitterionic surfactant suggest that it can be used in the mature oil fields for recovery of trapped oil.
Mogollón, J. L. (Halliburton) | Yomdo, S. (OIL India Limited) | Salazar, A. (Halliburton) | Dutta, R. (OIL India Limited) | Bobula, D. (Halliburton) | Dhodapkar, P. K. (OIL India Limited) | Lokandwala, T. (Halliburton) | Chandrasekar, V. (CMG)
The perception of better economics and less risk from infill drilling and recompletions are reasons well-focused remedies are preferred compared to reservoir-focused solutions, such as enhanced oil recovery (EOR). However, most literature does not discuss the economic and risk indicators driving this.
Using a real example, this work demonstrates that combining polymer flooding with infill drilling and recompletion substantially increases economic benefits with reasonable risk.
The reservoir considered is an Oligocene sandstone at a depth of 2700 m. The °API is 29.5 and permeability ranges from 50 to 500 mD. Current reservoir pressure is 43% of the original and it is below bubble point. A black oil model with a 133 × 56 × 128 grid was used. The model incorporated more than 50 years of matched primary and waterflooding production history and experimental polymer physico-chemical parameters. For the stochastic economic risks estimation, 1,000 iterations were run for each scenario considering uncertainties in injection-production, capital expenditures (CAPEX), operational expenditures (OPEX), and oil prices.
For a 20-year horizon, the injection-production-pressure profiles were numerically forecasted; economic results were calculated using a classic model and inputs from the forecast. The economic risk was determined stochastically. The redevelopment scenarios considered were as follows: Base: current waterflooding Existing wells interventions: workover, opening shut-in wells, and new perforations Infill drilling: vertical/horizontal infill drilling wells + existing wells operations Polymer flooding: using existing wells Combined Infill and polymer: vertical infill drilling wells and polymer flooding
Base: current waterflooding
Existing wells interventions: workover, opening shut-in wells, and new perforations
Infill drilling: vertical/horizontal infill drilling wells + existing wells operations
Polymer flooding: using existing wells
Combined Infill and polymer: vertical infill drilling wells and polymer flooding
P50 forecasts showed that interventions in existing wells in the base scenario increased oil production by 11% and net present value (NPV) by 71% with a risk index of 0.38.
A numerical optimizer was used to account for possible combinations of 14 potential drilling locations and vertical to horizontal well ratios. A scenario with three vertical wells was selected. Compared to the base case, this scenario showed an oil production increase of 23%, NPV increase of 178%, and a risk index of 0.41.
The injection rate of the polymer flood was optimized, resulting in a 17% increase in oil production and 95% increase in the NPV, with a risk index of 0.40. This justifies performing a polymer flood.
The most promising scenario is the combined infill drilling and polymer injection, which significantly improved the economic indicators—30% increase in oil production, 230% improvement of the NPV over the base scenario, with a risk index of only 0.41.
The results of this study demonstrate that the combination of EOR with different operational strategies results in significant benefits compared to the individual scenarios. Analysis of just oil production independent of economics and risk can be misleading. Infill drilling or flooding should no longer be the question. Instead, the question should be how they can be properly combined at various stages of asset life.
Nagar, Ankesh (Cairn Oil & Gas – Vedanta Limited) | Dangwal, Gaurav (Cairn Oil & Gas – Vedanta Limited) | Maniar, Chintan (Cairn Oil & Gas – Vedanta Limited) | Bhad, Nitin (Cairn Oil & Gas – Vedanta Limited) | Goyal, Ishank (Cairn Oil & Gas – Vedanta Limited) | Pandey, Nimish (Cairn Oil & Gas – Vedanta Limited) | Parashar, Arunabh (Cairn Oil & Gas – Vedanta Limited) | Tiwari, Shobhit (Cairn Oil & Gas – Vedanta Limited)
The Mangala, Aishwaya & Bhagyam (MBA) fields are the largest discovered group of oil fields in Barmer Basin, Rajasthan, India. The fields contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. The fields have undergone pattern as well as peripheral water injection. In order to overcome adverse mobility ratio and improve sweep efficiency thereby increasing oil recovery, chemical EOR has been evaluated for implementation in these fields. The potential benefits from chemical enhanced oil recovery (EOR) had been recognized from early in the field development. Polymer flooding was identified for early implementation, which would be followed by stage wise implementation of Alkaline-Surfactant-Polymer (ASP) injection in fields like Mangala. Since the commencement of polymer injection, the Mangala field polymer injectors have displayed multiple injectivity issues. In addition, the Aishwarya and Bhagyam fields are dealing with low Void Replacement Ratios (VRR) for their ongoing water injection, which if not rectified could adversely affect recovery. While various types of injector stimulations are being used, injectivity increases are short lived. A new technique termed as ‘Sand Scouring’ has been successfully applied resuting in sustainable injectivity gains.
The technique involves pumping creating a small fracture with a pad injected above fracturing pressure and then scouring the fracture face with low concentration 20/40 sand slugs in range of 0.5 to 1 PPA 20/40. The treatments are pumped at the highest achievable rates with the available pumping equipment within the completion pressure limitations. Based upon the available tankage, the scheduled is designed such that pumping of a fixed volume of sand stage, a quick shut-down allows for mixing the next stage of slurry. The pumping schedule and a ‘scouring’ intent is deliberately designed to avoid requirement of fracturing equipment, related cleanout equipment and resulting costs. The challenge of conformance is addressed by designing the pumping schedule to incorporate stages of particulate diverters and validated using pre and post injection logging surveys. .
Sand scouring jobs in 16 wells have been conducted across Mangala, Bhagyam & Aishwarya injectors. Out of thesewells, 9 wells had zero injectivity while the other 7 required both injectivity and conformance improvement. Most of the treated wells resulted in multifold improvement of injectivity as compared to their prior injection parameters. Sand scouring resulted in sustained injection performance when compared with prior conventional methods of stimulation. Injectivity improvements from sand scouring lasted for an average of 3 months days as compared to 14 days for the conventional stimulations. Sand scouring evolution, design, results and plans for future improvement are all discussed in this paper.
Varma, Nakul (Cairn Oil & Gas, Vedanta Ltd) | Nagar, Ankesh (Cairn Oil & Gas, Vedanta Ltd) | Manish, Kumar (Cairn Oil & Gas, Vedanta Ltd) | Srivastav, Pranay (Cairn Oil & Gas, Vedanta Ltd) | Nekkanti, Satish (Cairn Oil & Gas, Vedanta Ltd) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd) | Srivastav, Preyas (Cairn Oil & Gas, Vedanta Ltd)
This paper describes simulation solution for CT(Coil Tubing) based WBCO in flowing ESP/Jet Pump wells for scale/polymer debris deposition removal prior to any treatment in well, such as – Formation stimulation, ESP treatment, etc. It also describes prediction for requirement of Surface Well Test spread support to assist Nitrogen assisted WBCO. The paper describes new way of simulation for CT WBCO job in artificially flowing wells to predict decreased Liquid rate from reservoir, CT pressure & friction pressure losses. The modelling is done in Prosper and Cerberus, the results of which are validated with surface well test and Multiphase flow meter data recorded during the jobs. The results observed were very close to modelled with a number of advantages such as – No loss returns, higher lifting velocities, prediction of increased/decreased reservoir liquid rate affecting Motor winding temperature in ESPs, no settling of debris, post job Increased Liquid gain from well, decreased tubing friction pressure loss
Zagitov, Robert (Cairn Oil & Gas, Vedanta Ltd) | Venkat, Panneer Selvam (Cairn Oil & Gas, Vedanta Ltd) | Kothandan, Ravindranthan (Cairn Oil & Gas, Vedanta Ltd) | Senthur, Sundar (Cairn Oil & Gas, Vedanta Ltd) | Ramanathan, Sabarinathan (Cairn Oil & Gas, Vedanta Ltd)
Enhanced Oil Recovery is important stage of life cycle of a field and often it is implemented with challenges. In the chemical EOR, challenges and surprises are expected in production chemistry and production facilities operations. Partially hydrolyzed polyacrylamide used widely for controlling mobility ratio so that Operator is able to recover maximum possible oil. With complex water chemistry and rich in positively charged divalent ions, flooded polymer having negative charge interacts with divalent ions of produced water. Back produced sheared polymer interacts with divalent ions to form semi hard to hard scales poses challenges of the reliability of production facilities.
Other important limitations to be noted in CEOR phase are using production chemicals to control scale, emulsion and microbial treatment under Hydrogen Sulphide and waxy crude environment. This paper discusses about the requirement of preparedness and how to overcome challenges of EOR operations and in handling the back produced polymer in following areas: Selection of production chemicals to be compatible to polymer so that no or minimal degradation or loss of viscosity due to polarity of chemicals Performance of production chemicals in the presence of polymer Solids loading in production system Emulsion and produced water treatment Suitability of produced water treatment facilities Revised scaling and fouling control with back produced polymer with rich divalent ions present in produced water Strategizing chemical management system to suit polymer flood and polymerized back produced water treatment regime
Selection of production chemicals to be compatible to polymer so that no or minimal degradation or loss of viscosity due to polarity of chemicals
Performance of production chemicals in the presence of polymer
Solids loading in production system Emulsion and produced water treatment
Suitability of produced water treatment facilities Revised scaling and fouling control with back produced polymer with rich divalent ions present in produced water
Strategizing chemical management system to suit polymer flood and polymerized back produced water treatment regime
Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO2 content in reservoir fluid. A procedure was developed earlier to model the impact of reservoir CO2 on waterflood, polymer flood and ASP flood (
The objective of this work was to validate the modelling procedure developed to predict the produced gas rate in such a system with very high amount of CO2 in reservoir fluid.
A live oil coreflood experiment was carried out using 12 inches long Bentheimer core under Aishwariya reservoir pressure and temperature conditions. After saturating the core with live oil, the core was water flooded with brine for ~3.7 pore volumes. Produced gas volume was measured at different times so as to generate gas production profile.
Two different simulation techniques were used to simulate the experiment and match the gas production profile. First technique was using a compositional simulator with EOS based PVT while the other technique was using an "advanced processes simulator" modeling the component distributions based on partitioning coefficients. Both methods could successfully capture the production of gas from both liquid streams; oil and water and a reasonable match for the produced gas could be obtained.
The approach developed to simulate impact of CO2 on different aqueous based flooding processes in Aishwariya field was validated by matching the coreflood experiment carried out under actual Aishwariya reservoir conditions. It helped to confirm confidence in performance prediction of aqueous based flooding mechanisms planned in Aishwariya field despite the presence of significant amount of CO2.
The paper presents history match of unconventional produced gas profile of a coreflood carried out under Aishwariya field conditions with very high amount of dissolved CO2. The proposed method can be applied to estimate produced gas rate in other fields with very high amount of CO2 in reservoir fluid.
Agrawal, Nitesh (Cairn Oil & Gas, Vedanta Limited) | Chapman, Tom (Cairn Oil & Gas, Vedanta Limited) | Baid, Rahul (Cairn Oil & Gas, Vedanta Limited) | Singh, Ritesh Kumar (Cairn Oil & Gas, Vedanta Limited) | Shrivastava, Sahil (Cairn Oil & Gas, Vedanta Limited) | Kushwaha, Malay Kumar (Cairn Oil & Gas, Vedanta Limited) | Kolay, Jayabrata (Cairn Oil & Gas, Vedanta Limited) | Ghosh, Priyam (Cairn Oil & Gas, Vedanta Limited) | Das, Joyjit (Cairn Oil & Gas, Vedanta Limited) | Khare, Sameer (Cairn Oil & Gas, Vedanta Limited) | Kumar, Piyush (Cairn Oil & Gas, Vedanta Limited) | Aggarwal, Shubham (Cairn Oil & Gas, Vedanta Limited)
The objective of this paper is to present a suite of diagnostic methods and tools which have been developed to analyse and understand production performance degredation in wells lifted by ESPs in the Mangala field in Rajasthan, India. The Mangala field is one of the world’s largest full field polymer floods, currently injecting some 450kbbl/day of polymerized water, and a significant proportion of production is lifted with ESPs. With polymer breaking through to the producers, productivity and ESP performance in many wells have changed dramatically. We have observed rapidly reducing well productivity indexes (PI), changes to the pumps head/rate curve, increased inlet gas volume fraction (GVF) and reduction in the cooling efficiency of ESP motors from wellbore fluids. The main drivers for the work were to understand whether reduced well rates were a result of reduced PI or a degredation in the ESP pump curve, and whether these are purely down to polymer or combined with other factors, for example reduced reservoir pressure, increasing inlet gas, scale buildup, mechanical wear or pump recirculation.
The methodology adopted for diagnosis was broken in 5 parts – 1) Real time ESP parameter alarm system, 2) Time lapse analysis of production tubing pressure drop, 3) Time lapse analysis of pump head de-rating factor, 4) Time lapse analysis of pump and VFD horse power 5) Dead head and multi choke test data. With this workflow we were able to break down our understanding of production loss into its constituent components, namely well productivitiy, pump head/rate loss or additional tubing pressure drop. It was also possible to further make a data driven asseesment as to the most likely mechanisms leading to ESP head loss (and therefore rate loss), to be further broken own into whether this was due to polymer plugging, mechanical wear, gas volume fraction (GVF) de-rating, partial broken shaft/locked diffusers or holes/recirculation. In some cases a specific mechanism was compounded with an associated impact. For example, in ESPs equipped with an inlet screen, heavy polymer deposition over the screen was resulting in large pressure drops across the screen leading to lower head, but this also resulted in higher GVFs into first few stages of the pump, even though the GVF outside the pump were low, leading to further head loss from gas de-rating of the head curve. With knowledge of the magnitude of production losses from each of the underlying mechanisms, targeted remediation could then be planned.
The well and pump modelling adopted in the workflow utilise standard industry calculations, but the combination of these into highly integrated visual displays combined with time lapse analysis of operating performance, provide a unique solution not seen in commercial software we have screened.
The paper also provides various real field examples of ESP performance deterioration, showing the impact of polymer deposition leading to increased pump hydraulic friction losses, pump mechanical failure and high motor winding temperature. Diagnoses based on the presented workflow have in many cases been verified by inspection reports on failed ESPs. Diagnosis on ESPs that have not failed cannot be definitive, though the results of remediation (eg pump flush) can help to firm up the probable cause.
It has been demonstrated in both laboratory measurements and field applications that tertiary polymer flooding can enhance oil recovery from heterogeneous reservoirs, primarily through macroscopic sweep (conformance). This study quantifies the effect of layering on tertiary polymer flooding as a function of layer-permeability contrast, the timing of polymer flooding, the oil/water-viscosity ratio, and the oil/polymer-viscosity ratio. This is achieved by analyzing the results from fine-grid numerical simulations of waterflooding and tertiary polymer flooding in simple layered models.
We find that there is a permeability contrast between the layers of the reservoir at which maximum incremental oil recovery is obtained, and this permeability contrast depends on the oil/water-viscosity ratio, polymer/water-viscosity ratio, and onset time for the polymer flood. Building on an earlier formulation that describes whether a displacement is understable or overstable, we present a linear correlation to estimate this permeability contrast. The accuracy of the newly proposed formulation is demonstrated by reproducing and predicting the permeability contrast from existing flow simulations and further flow simulations that have not been used to formulate the correlation.
This correlation will enable reservoir engineers to estimate the combination of permeability contrast, water/oil-viscosity ratio, and polymer/water-viscosity ratio that will give the maximum incremental oil recovery from tertiary polymer flooding in layered reservoirs regardless of the timing of the start of polymer flooding. This could be a useful screening tool to use before starting a full-scale simulation study of polymer flooding in each reservoir.
Fredriksen, Sunniva B. (University of Bergen) | Alcorn, Zachary P. (University of Bergen) | Frøland, Anders (University of Bergen) | Viken, Anita (University of Bergen) | Rognmo, Arthur U. (University of Bergen) | Seland, John G. (University of Bergen) | Ersland, Geir (University of Bergen) | Fernø, Martin A. (University of Bergen) | Graue, Arne (University of Bergen)
An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.