A successful water injection management is a key to increase or stabilize oil production and to maximize oil recovery from a mature field. This paper describes an approach to draw maximum benefit through existing set up of a water injection in a mature offshore carbonate field of India. Water injection initiated after the six years of oil production and field is under water flood since last 28 years. The field witnessed favorable water flood condition and almost negligible aquifer support. During its long production period most of the producers had been sideracked from one to three times to target better saturation areas which has led to uneven subsurface water distribution. The field has also suffered less voidage compensation for quite some time.
To understand and mitigate the problem, a small pilot area within a field has been selected for implementing a good surveillance and monitoring program with pattern injection and possible intervention strategy. It was decided that based on the success of this pilot, the concept would be developed for implementation in step by step manner for entire field. The importance of multidisciplinary team has been recognized and detailed SWOT analysis was done for effective implementation of plan. Initially pilot area comprised of 15 oil producers and 4 water injectors. Conversion of one producer to water injector and restoration of water injection in 3 injectors were done as per plan and optimized injection rate (in this case maximum 3000 bbl per day) per injector were implemented. Peripheral pattern for pilot area with 5 injectors and 5 spot inverted patterns from rest 3 injectors were decided.
After one year of the implementation a thorough performance analysis of the pilot has been carried out which indicates the overall improvement of liquid and oil production rates along with reduction in GOR and decreasing trend of oil decline rates of producers.
The pilot approach has certainly helped to understand the Reservoir conformance in short duration of time. Encouraging results of this methodology guides to extent and implement this approach in other parts of field to cover the entire field in phased manner.
Abdulhadi, Muhammad (Dialog Group) | Tran, Toan Van (Dialog Group) | Chin, Hon Voon (Dialog Group) | Jacobs, Steve (Halliburton) | Suggust, Alister Albert (PETRONAS) | Usop, Mohammad Zulfiqar (PETRONAS) | Zamzuri, Dzulfahmi (PETRONAS) | Dolah, Khairul Arifin (PETRONAS) | Abdussalam, Khomeini (PETRONAS) | Munandai, Hasim (PETRONAS) | Yusop, Zainuddin (PETRONAS)
The first successful natural dump-flood in the Malaysian offshore environment provided numerous lessons learned to the operator. The minimal investment necessary for implementing the dump-flood coupled with the lack of recompletion opportunities in the subject wells suggested that direct execution without spending on expensive data gathering activity and extensive reservoir study makes more sense from a business point of view. A similar oil gain compared to a water injection project can be achieved at a significantly lower cost of USD 0.01 to 0.15 million in an offshore environment through dump-flooding.
The existing oil producers in the depleted reservoirs in Field B were originally completed and successfully drained oil from in a high-pressured watered-out reservoir below, making it an ideal dump-flood water source. The dump-flood was initiated by commingling the target and water source reservoir through zone change, allowing water to naturally cross-flow into the pressure depleted target reservoir. Once a memory production logging tool (MPLT) confirmed the cross-flow, the offtake well was monitored to determine the impact of the dump-flood and produce once the pressure was increased. Minimal investment was necessary because the operations were executed using slickline. The reservoir model will be calibrated once the positive impact of dump-flood is realized in the offtake well.
The first natural dump-flood in Reservoir X-2 has successfully produced 0.29 MMstb as of August 2018 with 600 BOPD incremental oil gain. The incremental recovery factor (RF) from the first dump-flood is predicted to be from 5 to 8%. Based on this success, it was decided to replicate the dump-flood project in other depleted reservoirs with Reservoir X-2 as an analog. Four reservoirs were subsequently identified, each with an estimated operational cost of approximately USD 0.01 million and potential incremental reserves of 0.10 to 0.20 MMstb per reservoir. The minimal investment necessary, the idle status of the wells and reservoirs, and the potential incremental reserves suggested that it is more appealing to proceed with implementing the dump-flood without undergoing an extensive and costly reservoir study. With reservoir connectivity being important to the success of dump-flooding, a more cost-effective approach would be to confirm the connectivity by monitoring the offtake well after the dump-flood is initiated. This approach provides more value because the cost of interference or pulse testing is significantly more expensive than the cost of the dump-flood itself while reservoir connectivity was already indicated as likely by geological data (map and seismic). Through a value driven approach, these dump-flood opportunities become more economically viable, allowing the operator to prolong the life of the assets and maximize the field profit.
This paper discusses using a value driven and business approach to implement the dump-flood in a mature field. Valuable insight into the business and technical considerations of implementing dump-floods are described, which are relevant to the industry, especially in today's low margin business climate.
Oil production decline and excessive water production are prevalent in mature fields and unconventional plays, which significantly impact the profitability of the wells and result in costly water treatment and disposal. To seek for a sustainable development of those wells, reducing the operation cost and extending their economic lives, this paper presents a method of synergistic production of hydrocarbon and electricity, which could harvest the unexploited geothermal energy from the produced water and transfer heat to electricity in the wellbore. Such method is cost-effective, since it does not require any surface power plant facility, and it is replicable in numerous wells including both vertical wells and horizontal wells. By simultaneous coproduction of oil and electricity, the value of existing assets could be fully developed, operation cost could be offset, and the economic life of the well could be extended.
This recently proposed method incorporated thermoelectric power generation technology and oil production. In this method, electricity could be produced by thermoelectric generator (TEG) mounted outside of the tubing wall under temperature gradient created by produced fluid and injected fluids. The aim of this paper is to illustrate the economic practicability of oil-electricity coproduction by using thermoelectric technology in oil wells based on previously proposed design. We examined the technical data of high water-cut oil wells in North Dakota and collected required information with respect to performance thermoelectric power generations. Special emphasis was placed on the key parameters related to project economics, such as thermoelectric material, length of TEG and injection rate. Sensitive studies were carried out to characterize the impact of the key parameters on project profits. We showed that by simultaneously production of oil and electricity, $234,480 of additional value could be generated without interfering with oil production.
The proposed method capitalizes on the unexploited value of produced water and generates additional benefits. This study could provide a workflow for oil and gas operators to evaluate an oil-electricity coproduction project and could act as a guidance to perform and commercialize such project to balance parts of the operation cost and extend the life of the existing assets.
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.
Temizel, Cenk (Aera Energy) | Balaji, Karthik (University of North Dakota) | Canbaz, Celal Hakan (Ege University) | Palabiyik, Yildiray (Istanbul Technical University) | Moreno, Raul (Smart Recovery) | Rabiei, Minou (University of North Dakota) | Zhou, Zifu (University of North Dakota) | Ranjith, Rahul (Far Technologies)
Due to complex characteristics of shale reservoirs, data-driven techniques offer fast and practical solutions in optimization and better management of shale assets. Developments in data-driven techniques enable robust analysis of not only the primary depletion mechanisms, but also the enhanced oil recovery in unconventionals such as natural gas injection. This study provides a comprehensive background on application of data-driven methods in oil and gas industry, the process, methodology and learnings along with examples of data-driven analysis of natural gas injection in shale oil reservoirs through the use of publicly-available data.
Data is obtained and organized. Patterns in production data are analyzed using data-driven methods to understand key parameters in the recovery process as well as the optimum operational strategies to improve recovery. The complete process is illustrated step-by-step for clarity and to serve as a practical guide for readers. This study also provides information on what other alternative physics-based evaluation methods will be able to offer in the current conditions of data availability and the understanding of physics of recovery in shale oil assets together with the comparison of outcomes of those methods with respect to the data-driven methods. Thereby, a thorough comparison of physics-based and data-driven methods, their advantages, drawbacks and challenges are provided.
It has been observed that data organization and filtering takes significant time before application of the actual data-driven method, yet data-driven methods serve as a practical solution in fields that are mature enough to bear data for analysis as long as the methodology is carefully applied. The advantages, challenges and associated risks of using data-driven methods are also included. The results of comparison between physics-based methods and data-driven methods illustrate the advantages and disadvantages of each method while providing the differences in evaluation and outcome along with a guideline for when to use what kind of strategy and evaluation in an asset.
A comprehensive understanding of the interactions between key components of the formation and the way various elements of an EOR process impact these interactions, is of paramount importance. Among the few existing studies on natural gas injection in shale oil with the use of data-driven methods in oil and gas industry include a comparative approach including the physics-based methods but lack the interrelationship between physics-based and data-driven methods as a complementary and a competitor within the era of rise of unconventionals. This study closes the gap and serves as an up-to-date reference for industry professionals.
Gupta, M K (Oil and Natural Gas Corporation Ltd) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd) | Singh, V K (Oil and Natural Gas Corporation Ltd) | Pawar, A S (Oil and Natural Gas Corporation Ltd) | Deuri, BUDHIN (Oil and Natural Gas Corporation Ltd)
In an offshore field, mitigation of H2S from natural gas itself is a big challenge. A situation where high H2S present in well fluid increases the challenges several fold to sweet both processed oil and gas. In a wellhead platform/remote location where manual intervention requirement is minimal, conventional process has several limitation such as space availability, load on structure, frequent monitoring etc., hence may not be suitable for mitigation of H2S from processed gas and oil.
In this work, an approach is adopted for sweetening of sour gas and sour crude in an optimum way, keeping offshore constraints in mind and without usage of rotating equipment's. An integrated simulation model is developed in Aspen HYSYS process simulator wherein well fluid from well manifold is processed in three phase oil and gas separator. The gas liberated from the separator is first sweetened in adsorption columns considering three bed systems unlike general usage of two. The oil is sweetened in an envisaged stripper column utilizing sweet gas from adsorption column as stripping gas. In this work, a three bed adsorption column is envisaged wherein 1st two column in used for sweetening of gas liberated from separator which consists of around 7500ppm H2S. Sour oil from the separator which contains around 2000 ppm of dissolved H2S is processed in a stripper column for mitigation of H2S dissolved in the oil. Sweet gas liberated from 1st two column of adsorber bed is used as stripping gas for oil sweetening. H2S liberated from stripper column is routed to the 3rd column for sweetening. After this gas from all the adsorber column is combined and routed to process platform along with the sweet oil. Analysis reveals that, this scheme can sweeten altogether both oil and gas to the desired H2S level without the need of any rotating equipment's and must be a suitable for remote location.
A holistic approach was taken for sweetening of oil and gas without the need of any rotating equipment's, & any chemicals, unlike the conventional method and hence can be suitably adopted for an offshore environment or at remote location where requirement of manual intervention is bare minimum.
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.
A case study on improving waterflood surveillance aided by a better understanding of the correlation between various water injectors and oil producers completed in the shallowest sub-layer of a giant multi-layered matured carbonate reservoir in Mumbai Offshore Basin is presented here. This understanding is then used to gauge effectiveness of the prolonged waterflood programme and to identify ‘target wells’ for optimizing water injection rate. The inferences of this analysis were tested using a simulation model.
Production, injection and pressure data of all wells completed in this sub-layer were extracted. The reservoir injection and withdrawal rates were computed using PVT data which were subsequently fed into an in-house developed streamline simulation program that generates a matrix of flow-based well rate allocation factors (WAF) correlating injection to withdrawal for each individual well as a part of its output. The analysis of injection efficiency per well was carried out in two scenarios viz. with current rates for effective waterflood surveillance and at a cumulative level with averaged rates to identify areas of deficiencies and optimize future injection rates.
Flow-based allocation factors provided a better picture than traditionally employed distance weighted technique owing to the underlying physics involved in describing streamline distribution in the reservoir. Results of analysis at the cumulative level indicated wells where injection efficiency, as measured by the ratio of injection rate to sum of streamlines-weighted withdrawal rates from connected producers, substantially deviates from 1. Few wells had an injector efficiency significantly higher than 1 which defined over-injection and potential recycling while a large number of injector wells had ratios of less than 1, highlighting the need to step-up injection rates and devise strategies for rigorous surveillance. To achieve the latter objective, injection-centric WAF's were regenerated at current situation with current rates and the dynamic nature of these factors could be observed by noting their slight difference with respect to previously estimated factors. This is attributed to averaged-out flow rates limiting the influence of newer high-rate producers and injectors. Nonetheless, wells in areas demanding attention are identified and requisite injection rates are assigned. These changes are included in the history-matched simulation model used for redevelopment activities and results were compared with a do-nothing case. The significant incremental recovery proves as a validation of the methodology adopted.
Waterflood surveillance on a well-to-well basis is always difficult in a matured field where water injectors are deployed in a ubiquitous fashion. This approach has rarely been employed in a reservoir of the size of Mumbai High and can be extended to other sub-layers subject to positive results from field implementation. Thus it is an endeavour to monitor waterflood effectiveness at a large field scale and could be beneficial for similarly developed fields.
Fiallos Torres, Mauricio Xavier (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin) | Ganjdanesh, Reza (The University of Texas at Austin) | Kerr, Erich (EP Energy) | Sepehrnoori, Kamy (The University of Texas at Austin) | Miao, Jijun (SimTech LLC) | Ambrose, Raymond (EP Energy)
Optimizing spacing of infill wells and fractures can lead to large rewards for shale field operators, and these considerations have influences on primary and tertiary development of the field. Although several studies have been employed to show the existence of well interference, few models have also implemented Huff-n-Puff and injection containment methods to optimize further hydraulic fracture designs and pressure containment to improve the efficiency of Enhanced Oil Recovery (EOR). This study has performed a rigorous workflow for estimating the impacts of spatial variations in fracture conductivity and complexity on fracture geometries of interwell interference. Furthermore, we applied a non-intrusive embedded discrete fracture model (EDFM) method in conjunction with a commercial compositional reservoir simulator to investigate the impact of well interference through connecting fractures by multi-well history matching to propose profitable opportunities for Huff-n-Puff application. First, based on a robust understanding of fracture properties, updated production data and multi-pad wellbore image logging data from Eagle Ford, the model was constructed to perform nine wells sector model history matching. Later, inter-well connecting fractures were employed for enhanced history matching where results varied significantly from unmeasured fracture sensitivities. The result is the implementation of Huff-n-Puff models that capture inter-well interference seen in the field and their affordable impact sensitivities focused on variable injection rates/locations and multi-point water injection to mimic pressure barriers. The simulation results strengthened the understanding of modeling complex fracture geometries with robust history matching and support the need to incorporate containment strategies. Moreover, the simulation outcomes show that well interference is present and reduces effectiveness of the fracture hits when connecting natural fractures. As a result of the inter-well long fractures, the bottom hole pressure behavior of the parent wells tends to equalize, and the pressure does not recover fast enough. Furthermore, the EDFM application is strongly supported by complex fracture propagation interpretation and ductility to be represented in the reservoir. Through this study, multiple containment scenarios were proposed to contain the pressure in the area of interest.
The model has become a valuable template to inform the impacts on well location and spacing, completion design, initial huff-n-puff decisions, subsequent containment strategies (e.g. to improve cycle timing and efficiency), and to expand to other areas of the field. The simulation results and understandings afforded have been applied to the field satisfactorily to support pressure containment benefits that lead to increased pressure build, reduced gas communication, reduced offset shut-in volumes, and ultimately, improvements in net utilization and capital efficiency.
Grover, Kavish (Cairn Oil & Gas, Vedanta Limited) | Kolay, Jayabrata (Cairn Oil & Gas, Vedanta Limited) | Kumar, Ritesh (Cairn Oil & Gas, Vedanta Limited) | Ghosh, Priyam (Cairn Oil & Gas, Vedanta Limited) | Shekhar, Sunit (Cairn Oil & Gas, Vedanta Limited) | Agrawal, Nitesh (Cairn Oil & Gas, Vedanta Limited) | Das, Joyjit (Cairn Oil & Gas, Vedanta Limited)
For any typical water flood or polymer flood management, maintaining optimum Voidage Replacement Ratio (VRR) is most crucial for optimizing reservoir performance. In a typical patternflood, a single injector supports many nearby producers, determining its contribution to particular producer is subjective and has inherent uncertainties. To avoid these uncertainties in allocation factor, a novel approach using simulation model based voidage compensation on pattern by pattern basis has been proposed in this paper.
History matched simulation model, which has been sectored into 5-spot producer centric patterns, forms the basis of this study. Voidage replacements are analyzed on these producer centric 5-spot patterns. Sectoral voidage created is determined using change in hydrocarbon pore volume (HCPV), water pore volume (WPV) and production from the sector. Sectoral Voidage Compensation Ratio (or Pseudo VRR) thus calculated is representative of the net change due to injection and production. The advantage is that it does not require any numerical allocation factor, rather is based on fluid movements within a pattern as predicted by the simulation model. This method thus provides a new approach to analyze pattern performance.
Along with VRR, pattern wise recovery and interwell channeling/cycling are the key parameters for any water flood performance analysis. A workflow has been proposed to rank the patterns based on these parameters and categorizing them into problem buckets. Actions corresponding to each bucket have been proposed. This forms the basis of strategizing improvements in well-by-well and pattern-by-pattern performance for optimizing field performance.