The Natural Gas Hydrate Program Expedition (NGHP) has been formed to explore and develop the gas hydrate resources of Indian subcontinent in three stages. The first stage was to identify the presence of gas hydrate deposits in Indian Offshore Basins and the second stage was to identify gas hydrate in sand rich geological setting within gas hydrate stability zone and suitable locations for production testing. During the second stage, 42 gas hydrate wells at 25 sites were completed in deep water areas of Krishna Godavari and Mahanadi offshore in Eastern Coast of India.
This paper provides an insight into formation evaluation techniques as effective tools of evaluating gas hydrate saturation. During the second stage of the expedition; LWD, wireline well log data and pressure cores were acquired and they have been used for estimation and validation of gas hydrate saturations. The gas hydrate saturation have been estimated by three methods viz., standard deterministic Archie method, probabilistic method using ELANPlus model and Density Magnetic Resonance (DMR) technique. This paper also emphasizes the estimation of gas hydrate saturation considering gas hydrate as a part of matrix in the ELANPlus model and validation with pressure core results.
In Petrophysical model, hydrate can be considered either as a pore-filling hydrocarbon (fluid) or as a matrix mineral (rock constituent). When it is assigned as a pore-filling hydrocarbon, the model calculates the matrix volumes & porosity and calculates the water saturation in the same way as the basic interpretation model. When the hydrate is considered as a constituent of the matrix in the model, hydrate volume is calculated and the hydrate saturation is then arrived at by dividing this volume by the total porosity.
Hydrate is invisible to Nuclear Magnetic Resonance (NMR) measurements. In DMR technique, the deficit in NMR porosity as compared to Density porosity is used to estimate the hydrate volume accurately.
Gas hydrate saturation estimation in one of the well drilled during the second stage of the expedition from Krishna Godavari basin is discussed in detail in this paper. Gas hydrate saturation estimated from DMR method is found to be close agreement with other methods such as deterministic Archie and ELANPlus based probabilistic methods. The gas hydrate saturation is found to be in the range of 20-60% in the considered well. The results have been validated with gas hydrate saturation obtained from pressure cores retrieved from the nearby core hole.
The present approach is to estimate gas hydrate saturation with different methods and validation with pressure core data to minimize uncertainty in estimation of petrophysical parameters for such type of unconventional reservoirs.
Kisku, Sayanima (Oil & Natural Gas Corporation Ltd.) | Santhosh Kumar, R. (Oil & Natural Gas Corporation Ltd.) | Dayal, Har sharad (Oil & Natural Gas Corporation Ltd.) | Chadha, Harish Kumar (Oil & Natural Gas Corporation Ltd.) | Srivastava, Anil (Oil & Natural Gas Corporation Ltd.)
Infill drilling is an integral part of brown field management for exploiting un-drained areas with good oil saturation. In a matured field on water-flood, the primary objective is optimized wellbore placement of infill wells in areas with better petro-physical characteristics, bypassing flooded region. It is also important to design a robust completion strategy to safeguard the longevity of these wells by curtailing produced water. This approach assists in dramatic increase in production by isolating water charged sections and thereby restricting rise in water production.
The use of advanced Logging-While-Drilling techniques during horizontal drilling provides an opportunity for effective well planning. Real-time Logging-While-Drilling instruments during directional drilling gives us the opportunity to acquire information pertaining to the reservoir in a single run. Interpretation from the real-time data acquisition boosts the planning during wellbore drilling.
This paper discusses a case study of a field in western offshore, India, which focuses on the applications of geosteering and the use of swell packers for zonal isolation to augment oil production. In this study, two wells have been deliberated where the real-time information has been extracted and included in the decision making process. The bottom-hole assembly used in this case, comprised standard Logging-While-Drilling services such as gamma ray, resistivity, neutron porosity, density and density imaging services and also formation pressure testing.
Since the field under study is a carbonate reservoir that has been on waterflood for the last twenty eight years, chances of early breakthrough of water in the infill wells has posed a high risk in spite of the presence of good bypassed oil saturation. Geosteering has enabled to restrict the horizontal section safely within the desired zone of better oil saturation and geological features, as interpreted from the Logging-While-Drilling data. Further isolation of suspected water bearing zones with swell packers have assisted in healthy well completion by diminishing chances of sharp rise in water cut in the infill wells.
The negative impacts of high water cut in mature fields are well known within the oil & gas industry. Water production preventive & mitigative measures are well established and documented: Wireline or coil tubing conveyed diagnostic and work-over operation(s) is one of such common preventive measures. This paper, through a series of integrated case studies will highlight the best practices for wireline conveyed logging and work-overs with one common goal, i.e. to achieve the water production to a minimum acceptable level in deviated high water cut wells.
The prolific XYZ field is located in the Northern North Sea and it produces oil from Jurassic Brent Group. Oil production from the XYZ reservoir started in early 1978, with 43 producing wells and 15 water injection wells targeting the Rannoch, Etive, Ness and Tarbert sands. Oil and gas production peaked in 1982 and since then production has steadily declined for this field. The increasing water cut in the wells of this field is presenting a challenge for the operating companies.
Production profiling using advanced Production Logging data, casing/tubing integrity check using Multi-Finger Caliper data and saturation monitoring using cased-hole Reservoir Saturation data was done in these wells to ascertain the water producing zones and do the subsequent well intervention, if required. A strategic diagnostic test was designed to precisely evaluate the flow profile using advance production logging tool consisting of 5 mini-spinners & 6 sets of each electrical and optical probes; Real-time data assessment and analysis was done for different flowing rate surveys to validate the findings. Additionally, casing condition was evaluated using Multi-Finger Caliper to decide Plug or Straddle setting depths. Also, new hydrocarbon bearing zones were identified based on cased-hole saturation tool results. The analysis results boosted the cumulative oil production.
This study demonstrates the importance of making real time interpretation decisions at the wellsite and the benefit of developing a good working relationship between wellsite engineers and onshore technical support. The results of this work led to the unequivocal determination of major oil and water producing zones in deviated high water cut (95%+) wellbores which further helped in taking workover decisions to carry out water shut off, utilizing either plug or straddle technology. The findings of caliper data determined the appropriate plug or straddle setting depths. The results were compared and confirmed with the nearby well dynamic pressures and production data.
The technical approach and processes applied to wells of XYZ field is a valuable example guide to decide water shut off zones and technique of similar plays. This study consists of three integrated case studies from a mature field where water shut-off zones and technologies were decided based on the findings of production logging and well integrity data. Also, re-perforation jobs were performed based on the cased-hole reservoir saturation data results. These strategic workover operations ultimately led to significant increase in hydrocarbon production.
Immiscible water-alternating-gas (iWAG) flooding is often considered as a tertiary recovery technique in waterflooded or about-to-be waterflooded reservoirs to increase oil recovery due to better mobility control and potentially favorable hysteretic changes to phase relative permeabilities. In such cases, typically, reservoir simulation models already exist and have been calibrated, often modifying saturation functions during the history matching stage. However, to utilize such models in forecasting iWAG performance, additional parameters may be required. These can be acquired by simulation of WAG coreflood experiments. While in many published cases, the parameter values obtained from matching experimental results are used without modification, this may not be advisable since the parameters are only valid at the core scale at which they were obtained. This paper discusses the challenge of systematically upscaling WAG parameters obtained at core scale to an existing full field model.
In this work, we use a multi-stage upscaling process from core scale to full field scale. The first stage uses a core scale model to match ‘representative’ core flood experiments and obtain WAG parameters. The second uses a well-to-well high-resolution 1D section of the full field model populated using gridblocks of core size to generate ‘reference’ WAG performance using the unaltered WAG parameters obtained from core. The third stage uses a similar 1D model but populated using gridblocks at full field model resolution to match the results from the reference model while adjusting the WAG parameters as little as possible. Finally, a model using the full field model resolution as well as the full field relative permeability functions which, it is assumed, have been tuned to match the history and account for dispersion is used to match the reference model results and obtain final upscaled WAG parameters.
The upscaled WAG parameters obtained at the end of this multi-stage process can be used at the field scale. This process allows clear quantification of the uncertainty associated with the upscaling process. Simulations at the third stage showed that once the full field to core scale grid size ratio exceeded a certain point (2500:1), there was a marked increase in the difference between upscaled and reference model results. It was found that if WAG parameters were changed in the full field model resolution model in order to match recovery results in the reference model, Land's parameter could change by up to 10% and relative permeability reduction factor could increase by up to 30% although it is expected that this will vary from case to case. It is therefore recommended to identify and use full field model resolutions to as close to the threshold as possible. The practice of using the core scale iWAG parameters in the full field model directly could under-estimate actual recovery, and overestimate injectivity. When considering the WAG mechanism alone, the value of the recovery underestimate increasing with pore volumes injected and, in our case, by up to 7% after injecting 1 pore volume of fluid.
This multi-stage simulation approach helps identify the adjustments required and uncertainties associated with simulating iWAG flooding in reservoir models. This approach utilizes options widely present in commercially available finite difference simulators, addresses the challenge of utilizing existing pseudo functions and provides a practical methodology through which iWAG performance forecasting can be improved.
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.
Mandal, Dipak (Oil & Natural Gas Corporation Ltd) | Baruah, Nabajit (Oil & Natural Gas Corporation Ltd) | Jena, Smita Swarup (Oil & Natural Gas Corporation Ltd) | Nayak, Bichitra (Oil & Natural Gas Corporation Ltd)
Hydrocarbon gas injection into the reservoir is one of the most effective EOR processes. In case of a dipping and light oil reservoir, immiscible gas injection can give further impetus to the oil recovery. Since, average current gas saturation in the subject reservoir has become high due to depletion rendering water injection at this late stage is found to be ineffective, scope of gravity assisted immiscible gas injection as an alternative has been evaluated to assess its impact on reservoir pressure and ultimate recovery.
The present study pertains to a high permeable clastic light oil reservoir with reasonable dip, belonging to an old field of South Assam Shelf of India under production since 1990 with current recovery of 22% of STOIIP. The reservoir being undersaturated with no aquifer support, shows significant decline in reservoir pressure (260 ksc of initial pressure to current level of 50 ksc). Simulation study has been carried out on a fine scale geo-cellular model. Multiple realizations have been created considering combinations of oil producers and gas injection wells assigning varied rates to study the different development scenarios and impact on recovery improvement. The study indicates an incremental oil recovery of about 14% of STOIIP by immiscible gas injection.
Based on the study, immiscible gas injection has been initiated in the reservoir on pilot scale basis through two gas injectors with continuous monitoring. After gas injection during last one year, reservoir pressure increased about 25 ksc and consequently per well productivity also increased. Non-flowing well starts producing and currently sand is producing nearly 25% higher than earlier production before gas injection. Based on the encouraging result from pilot gas injection, decided to expand the process at field level and subsequently drilling of new oil producers after jacking up of reservoir.
The study has brought out that the gas injection into shallower portion of the reservoir yields better sweep efficiency to displace the oil to the deeper portion of the reservoir due to the gravity effects and hence, appropriate locales of the reservoir are targeted for additional input generation to augment the oil recovery.
Baruah, Nabajit (Oil & Natural Gas Corporation) | Mandal, Dipak (Oil & Natural Gas Corporation) | Jena, Smita Swarupa (Oil & Natural Gas Corporation) | Sahu, Sunil Kumar (Oil & Natural Gas Corporation)
This paper examines the prospect of Gas Assisted Gravity Drainage (GAGD) process in improving recovery from a sandstone reservoir by injecting produced gas back into the crestal part of the reservoir. Besides recovery improvement, immiscible gas injection ensures near Zero Flaring strategy. The process has been found to be ideal in reservoirs with high permeability and reasonable dip to maximize oil production wherever a sufficient gas source exists. Based on the study, gas injection is recommended at the crestal part of the reservoir under study at the rate equivalent to the produced gas to maintain pressure, arrest gas cap shrinkage and improve recovery.
Shiwang, Rahul (Baker Hughes, a GE company) | Banerjee, Anirban (Baker Hughes, a GE company) | Ramaswamy, Vijay (Baker Hughes, a GE company) | Malik, Sonia (Baker Hughes, a GE company) | Deshpande, Chandrashekhar (Baker Hughes, a GE company) | Kumar, Sanjeev (ONGC Ltd.) | Chadha, A. K (ONGC Ltd.)
The identification of fluid saturations in depleted reservoir sands is critical to understand the reservoir potential and field life. However, in case of water flooding, the formation water salinity of the reservoirs sands might be altered and fluid saturations from conventional petrophysical analysis can be misleading. This will have direct impact on the field economics. A salinity independent saturation computation from Carbon/Oxygen (C/O) log becomes a necessity in such development wells– a first of such application in a field under secondary recovery for this basin.
C/O well logging has been extensively used in cased hole environments to determine saturation behind casing. They are used essentially to determine oil saturation in cased hole conditions for depleted reservoirs. While their cased hole applications have been well established; for the study well, a pulsed neutron tool was used in an open hole environment to determine the fluid saturations to compare against the saturations computed from conventional resistivity logs. This study helped in the determination of fluid saturations in mixed salinity reservoir sands, which were to be explored from subsequent wells in the field.
The hydrocarbon-bearing sands in the field were water injected in nearby wells to enhance recovery. Development wells drilled in the field relied on petrophysical evaluation from conventional open hole data and pressure testing and fluid sampling depths were determined accordingly. A pulsed neutron tool was deployed in an open hole well after operational constraints were encountered with the formation testing tool. As an alternative, the pulsed neutron data were acquired in the well to compute salinity independent water saturation based on C/O log response as against the fluid saturation computation from resistivity logs. The determination of fluid saturations from C/O helped in determination of altered salinity for the sand intervals in the field. For the study well, C/O-derived water saturation was found to be higher than that from resistivity log computation. This was significant in identification of water breakthrough in the bottom interval of the reservoir sands.
This paper details the method and findings of C/O logging in open hole environment from Western Onland Basin in India. The critical solutions provided for the reservoir sands in the field and enabled the operator to save significant well cost and rig time by making informed decision of not lowering the casing in this well section.
The paper discusses a petrophysical evaluation method for complex tight gas formations in a mature and partially depleted gas condensate field in Oman, allowing a full petrophyscial evaluation as well as geomechanical modeling from a source-less petrophysical dataset, thus reducing operational data acquisition risk in partially depleted reservoirs without compromising on hydraulic fracturing design. The developed methodology includes the volume of shale estimation from correlation with Poisson's ratio for the feldspathic rich tight formation. This methodology was used in deep tight fields in Oman for more than 3 years in both vertical and highly deviated wells greatly reducing the risk, logging cost and complexity of operations.
Mishra, Gaurav Kumar (Oil and Natural Gas Corporation Limited) | Meena, Rakesh Kumar (Oil and Natural Gas Corporation Limited) | Mitra, Sujit (Oil and Natural Gas Corporation Limited) | Saha, Kunal (Oil and Natural Gas Corporation Limited) | Dhakate, Vilas Pandurangji (Oil and Natural Gas Corporation Limited) | Prakash, Om (Oil and Natural Gas Corporation Limited) | Singh, Raman Kumar (Oil and Natural Gas Corporation Limited)
India is the fastest growing major economy and third largest CO2 emitter in the world. Keeping cognizance of country's energy requirement and commitment to climate change, embarking upon technologies having minimal carbon footprint is the need of the hour. Carbon capture, utilization and storage (CCUS) is one such technology which offers dual benefits of carbon sequestration & enhancing oil production from mature oils fields. This paper outlines ONGC's efforts in bringing nation's first CO2-EOR project.
In view of non-availability of natural CO2 sources in India, usage of anthropogenic CO2 captured from thermal power plants was conceptualised. Based upon CO2 source-sink matching exercise and favourable reservoir & fluid parameters, two oil fields were screened. Technical feasibility of CO2-EOR was first ascertained in laboratory by determination of minimum miscibility pressure (MMP) of CO2 through slim tube experiments. Encouraged by laboratory results, full field compositional simulation studies along with fluid characterization inputs from PVT simulator were carried out.
The MMP were found to be in range 190-250 Ksc, which is below the initial reservoir pressures of the targeted reservoirs. The proposed scheme entails drilling of around 70-80 wells inclusive of both producers & injectors and has the potential to yield an incremental recovery between 10-14 %. A sensitivity analysis based upon purity of CO2 and its adverse effect on MMP was carried out in terms of reduced oil recoveries. Since, this shall be a CCUS project, CO2 from the produced stream has to be separated, compressed and reinjected in a closed loop system. Around 5-8 MMT of CO2 will be sequestrated through Structural, Solubility and Residual trapping mechanisms as modelled in compositional simulator. IFT reduction & decrease in Sor (Residual oil saturation) as result of swelling, miscibility of CO2 with native oil were also modelled in simulator. Being first of its kind project in India, there are many inherent challenges to the CCUS project. At the source end, capturing CO2 from flue gas stream and its compression & transportation is a cost and energy intensive process. At the Sink end, CO2 being acidic and corrosive gas will need retrofit modifications in terms of special corrosion resistant metallurgy for existing processing facilities.
The learning curve from this endeavour shall create knowledge base to further expand deployment of CCUS in India, bringing a large portfolio of reservoirs under the ambit of CO2-EOR. Success of CCUS in India will not only increase domestic oil production but also cater to address the National INDC of reducing emission intensity of GDP by 33-35 percent by 2030 as per Paris agreement.