A porosity segmentation technique has been proposed in this work. Scanning Electron Microscopy (SEM) is often used as a non-destructive technique to obtain microscale images of rock samples. These images pose various difficulties before the user. Unlike sandstones, carbonates display a large heterogeneity in their pore-size distribution owing to their evolution. Additionally the quality of the image often mandates several image processing steps before they can be used for interpretation tasks. This variation appears due to irregular distribution of intensities in the pixel values of the SEM image. Conventional techniques of global binarization used in extracting the porous part suffer due to this reason. This work introduces a novel method of optimizing the various image processing parameters for proper extraction of porous part. The proposed method implements the Simulated-Annealing (SA) based global optimizer for finding optimum values of these parameters. Results of the application on five SEM images have been shown. The images are processed with optimum choice of parameters after preprocessing. Finally, we report the total porosity in terms of pore and throat porosity.
Sengupta, Partha (Oil and Natural Gas Corporation Limited) | Katre, Narendra (Oil and Natural Gas Corporation Limited) | Suman, Abhinav (Oil and Natural Gas Corporation Limited) | Das, Barnali (Oil and Natural Gas Corporation Limited) | Pawar, Anil (Oil and Natural Gas Corporation Limited) | Deshpande, Sunil (Oil and Natural Gas Corporation Limited)
In any onshore gas installation, bath-heaters and high pressure separators are provided as standard surface facilities to take production from high pressure wells having hydrate forming tendency. Medium pressure separators are also provided to take production from medium pressure gas wells. The paper deliberates on an optimized surface installation for handling high pressure well fluids with possibilities of hydrate formation. The study has been carried out through steady state multiphase simulation considering pressure & production profile of the wells, consumer requirement and flow assurance i.e. hydrate formation. An optimized process scheme and production strategy is presented for early production from both high pressure and medium pressure gas wells in a single separator and without any bath heater.
Based on well test data, well completion data and pressure profile, simulation studies are carried out in steady-state multiphase flow simulation software to look into possibility of hydrate formation in the flow lines or in process piping. Flow from wells having high well-head pressures in the range of 120 to 165 kg/cm2g (ksc) are simulated by varying the separator pressure, flow line size & length and choke arrangement. Flow simulations are carried out for different choke combinations and flow line arrangements to keep well fluid temperature above hydrate formation temperature in the entire flow path from well head to separators.
It was established from simulations that flow from the well having highest production as well as highest well head pressure of 165 ksc can be taken by operating the separator at 33 ksc and adopting a multi-choke arrangement along the flow line without any possibility of hydrate formation in the system. The multi-choke arrangement consists of putting chokes including well head choke at well site, at installation inlet and the final choke at installation inlet manifold. The arrangement also envisages additional small length of flow line as buried portion near installation inlet to take advantage of heat gain from soil. From 2nd year onwards of the profile period, it is observed that with reduction in well head pressure to 132 ksc as per profile, the well can be produced by operating the separator at lower pressure without any hydrate formation. For rest of the wells, only multi-choke arrangement is found to be sufficient to prevent hydrate problem while operating the separator at even lower pressure throughout the profile period. It is also observed that higher production can be taken from the wells from 2nd year onwards on account of operating the separator at lower pressure.
The optimized scheme has marked deviation from the earlier proposed standard scheme with substantial reduction in number of equipment and consequent reduction in CAPEX & OPEX. This novel process scheme and production strategy eliminate the need for investment in both high pressure separator and hydrate mitigation measures like heat tracing, methanol injection or bath-heaters. This innovative production strategy also facilitates better recovery from the gas wells on account of operating the separator at lower pressure.
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.
Sengupta, Partha (Oil and Natural Gas Corporation Limited) | Deshpande, Sunil (Oil and Natural Gas Corporation Limited) | G., Sharmila (Oil and Natural Gas Corporation Limited) | Das, Barnali (Oil and Natural Gas Corporation Limited) | Pawar, Anil (Oil and Natural Gas Corporation Limited)
LPG production from a gas processing plant was experiencing gradually decreasing LPG production in spite of having feed gas rich in heavier hydrocarbons. The process involves dehydration of feed gas, cooling the gas in a propane based chiller to condense heavier hydrocarbons, processing the liquid in a De-ethanizer column to separate C3 components and further separate the C3/C4 (LPG) and C5 components in a Debutanizer column. To understand the above phenomenon, a steady state model of the plant was developed using licensed commercial process simulation software. The crucial process parameters required for efficient recovery of LPG are then identified and their optimum values established through simulations. Further experiments were carried out during plant operation to identify the bottlenecks in maintaining the parameters at optimum levels. From simulations it was observed that De-ethanizer pressure, De-butanizer reflux condenser outlet temperature and De-butanizer reboiler temperature have the major effect on LPG components loss. From real time monitoring of operations, it was observed that there was difficulty in maintaining De-ethanizer pressure and De-butanizer temperature profiles at the optimum levels. It was concluded that an ineffective air cooled condenser, a passing manual valve and an improperly tuned temperature controller were the root causes behind sub-optimal operation. Accordingly, recommendations were made for rectifying the problems and the same have been accepted by the plant engineers for implementation which will result in LPG production gain by 20 %.
Methyl Di-ethanol Amine (MDEA) based Gas Sweetening Process is an established process for treatment of sour gases to meet pipeline specifications with regards to H2S contents. One of the Gas Sweeting Unit (GSU) has been designed with generic MDEA solvent to selectively remove H2S along with 32% Co-absorption of CO2. It was observed that because of higher receipt of sour gas, all GSU trains were operating with higher feed gas throughput resulting in higher H2S content in sweet gas & higher quantity of acid gas generation. A detailed study was carried out to explore the possibilities for maintaining sweet gas quality with increased sour gas throughput.
Detailed simulation studies on "HYSYS" process simulator revealed, that using generic MDEA it was difficult to increase the operating capacity of the GSU while maintaining H2S content in sweet gas & acid gas quantity generation within acceptable limits. Hence opportunities for speciality amines were explored.
Case studies revealed successful use of specialty amines for capacity enhancement and improved performance in the existing system. With the targeted sweet gas quality, the capacity can be enhanced up to 30% with minor modifications in the existing set up. This also resulted in significant reduction in consumption of utilities like steam, power and cooling water.
Gondalia, Ravi Ramniklal (Schlumberger) | Kumar, Rajeev Ranjan (Schlumberger) | Nand, Ujjwal (Schlumberger) | Bandyopadhyay, Atanu (Schlumberger) | Narayan, Shashank (Schlumberger) | Bordeori, Krishna (Schlumberger) | Singh, Mukund Murari (Schlumberger) | Shah, Arpit (Schlumberger) | Das, Santanu (Oil and Natural Gas Corporation Limited) | Rao, Dasari Papa (Oil and Natural Gas Corporation Limited) | Shaik, Moulali (Oil and Natural Gas Corporation Limited)
The Mandapeta-Malleswaram field in India comprises Triassic-Jurassic age sands found at 4000m– 4500m depth, where reservoir pressure ranges 6,000 psi to 9,500psi with static temperature up to 340°F. This tectonically active basin with strike slip stress regime causes a heterogeneous distribution of in-situ stress which complicates the design and execution of effective hydraulic fracturing treatments. Previous attempts at fracturing from 2013 to 2017 were not successful and geomechanics inputs were different from actual values. This paper describes the lifecycle of a production enhancement project, from construction of a geomechanics-enabled mechanical earth model (MEM) to the successful design and execution of fracturing jobs on nine wells increasing proppant placement by 250% compared to previous hydraulic fracturing campaign and achieving 730% incremental gain in gas production compared to pre- fracturing production.
Challenges like fracture modeling in tectonically stressed formations, issues of proppant admittance, and complicated fracture plane growth in highly deviated wells (>65°) were overcome by Geomechanical modeling. The modeling incorporated advanced 3D anisotropy measurements, providing better estimation of Young's modulus, Poisson's ratio, and horizontal stresses, resulting in realistic estimation of closure and breakdown pressure. Fault effects were modeled and taken into consideration for perforation depth selection and estimation of pumping pressure with model update based on extensive Minifrac injections and analysis.
This study describes the results of injection tests (step rate, pump in-flowback, and calibration injection tests) carried out in the field addressing specific challenges in each well. Pre frac diagnostic injection and decline analysis was used to calibrate the MEM and tailor the design for every well. Proper job preparation for well completions and extensive stability testing involving a borate-based fluid system has reduced the screen out risk and enabled successful fracture placement. Effective pressure management on the job eliminated the problem with frequent screen outs and led to successful execution of all nine jobs while increasing the average job size from 30 t to ~150 t of proppant per stage.
From this project, a practical guide to address issues of multiple complexities occurring simultaneously in a reservoir, such as the presence of tectonic stress, fracture misalignment, fissure mitigation, and high tortuosity was developed for future application in tectonically complex fields.
The subsurface geological complexities in Krishna Godavari Basin, India often result into discrete and challenging reservoirs. Limited geological correlation plus HP-HT regime down-hole further add up to the challenge to understand reservoir HC potential. In this context, application and meaningful interpretation of gas ratio analyses are discussed in reservoir sections of two exploratory wells (A & B of L. Cretaceous and L. Eocene) from KG Basin.
Formation Gas data obtained during drilling are commonly analyzed as well-known ratios of ‘Dryness’, ‘Wetness’, ‘Balance’, ‘Character’ & ‘Pixler ratios’ which are simple, quick and field based. It is a proxy that can save time and resource; by aiding in identification of reservoir fluids, fluid contacts & choosing testing intervals, thus enhancing confidence about reservoir. It can be practiced especially where log quality is poor and in cases where logging scope is limited due to complications or high thermal regime.
It is found that gas ratio studies indicate gas-condensate in Well-A while gas with light crude oil in Well-B reservoirs. Moreover it is capable of picking up top of reservoir facies, gas-water & gas-oil contacts and variation in reservoir tightness across reservoir sections as found in Well-A & B. The comparative approach of ratios also interprets about presence of several discrete yet closely spaced HC pools across the reservoir section of Well-B. These findings simply enhance understanding of otherwise complex reservoirs. Along with petrophysical analysis it adds confidence to propose precise testing intervals against HC fluid of interest.
Since gas-ratios are proxy of fluid contacts, their utility can be extended to drilling reservoir lateral wells, if compositional gas data can be obtained fast- in which case gas-ratio analysis can guide drilling effectively to avoid deviation to unwanted fluid zone although reservoir litho-facies variation is less. Gas ratios and electrologs are integrated to introduce to a practical concept of Oil Potential Parameter (OPP) to evaluate effective extent of arenaceous reservoir and reduce qualitative geological risk while planning wells to develop an oil field, as shown with a KG basin example.
With known basement hydrocarbon accumulation, Mumbai High field in Western Offshore, India is a priority area for extending the concept of fracture characterization in metamorphic basement reservoirs. Basement in Mumbai High is hydrocarbon bearing in few areas proximal to major fault damage zones and intersections of major regional tectonic cross trends. The challenge lay in characterizing such basement reservoirs with significant heterogeneities in mineralofacies, in situ stress fields, seismic amplitudes, fracture properties and connectivity, and flow potential. This necessitated development of an integrated static fracture model workflow assimilating structural modeling, seismic and petro-physical interpretations for fracture drivers and geocellular fracture modeling, fine tuned using geological concepts and point data extracted from well data analyses. The deterministic geo-cellular fracture model thus prepared has been calibrated with real time well observations and has been found to satisfactorily explain anomalous hydrocarbon accumulation and flow pattern in basement wells tested in the area. The adopted workflow has helped planning wells for evaluating and exploiting basement reservoir as well for real time monitoring of wells.
ASP flooding process has emerged as cheaper alternative of conventional micellar–polymer flooding. Process has economically produced incremental oil over water flood in field on pilot scale by reducing the capillary forces trapping the oil and improving the overall contact efficiency. Process is designed to combine the best feature and eliminates some of negative aspect of each process of Alkaline, Surfactant and Polymer flooding.
Present paper deals with the application of ASP technology in Viraj field of Ahmedabad Asset. The Viraj rock is sandstone rock with average porosity is 30% and permeability ranges 1-10 Darcy. The reservoir crude has viscosity of 50 cP at reservoir temperature of 81°c with acid number of1.805 milligram per gram of crude oil. Viraj crude is viscous in nature. Hence sharp viscosity/mobility contrast is exiting in primary production mechanism. In view of above, ASP process appears to be best feasible technology for maximizing the ultimate recovery.
A four inverted 5-spot pattern has designed on the basis of encouraging laboratory results. Conventional method of reservoir engineering were applied for performance prediction of oil recovery in the field condition and an additional recovery was estimated 18% of pilot OIIP over water flood (32%). Surface facility and injection schedule was prepared by in-house expertise. ASP plant has been commissioned on 10th August-2002. An MDT team was formed for monitoring the ASP pilot accordingly a monitoring manual was prepared for surveillance. Polymer samples were collected from polymer storage tank, after pumps and at injector well heads for quality control of injection polymer. Wells head samples of all 9 pilot producers and some offset well were carried out for tracer breakthrough/ injected chemicals break through to know the flood front advancement. Three different type of tracers were injected in three injectors followed by ASP slug injection @ 200 m3/d per well. It was estimated that 58000 m3 of additional oil was produced and decrease in water cut of about 10% by ASP process. Before implementation the ASP pilot in July'2002, the liquid production was at its highest@ 1560 m3/d and corresponding oil rate and water cut were 152 m3/d and 89%. After implementation of ASP pilot, water cut declined to 72% by April'2003 and oil production increased to 260 m3/d, indicating the efficiency of ASP flooding. Subsequent rise in liquid withdrawal could not contain water cut rise and regained a level of 80%+. The tracer and chemical breakthrough was observed in almost all the pilot producers and some offset wells. It showed that front was moved uniformly in all direction, same was confirmed later by simulation study. During the pilot implementation imbalance in injection and liquid production was observed due to completion problems of five producer in both the layers, as confirmed by simulation study in April' 2010. Simulation study validated the decreases in oil saturation in pilot area by moving the mobile oil towards down-dip side of structure. This mobile oil by ASP slug was trapped by drilling 9 infill locations and on sidetrack wells. This has led to increased oil production from 100 m3/d in March'2010 to a level of 160 m3/d whereas water cut has remained more or less at around 83%. The cumulative oil produced by these ten infill locations was 98476 m3 as on Nov'2015. A total oil production by EOR and mobilized oil obtained by IOR (infill locations) was 156476 m3 which is about 87% of envisaged oil production from pilot.
The success of this first ASP pilot tested in Viraj field of Ahmedabad Asset, India led field pilot expansion for commercialization.
This paper deals with the use of Side Wall Cores as a tool to monitor In-Situ Combustion (ISC) process performance in Balol field of ONGC where ISC process is being applied on commercial scale since 1997.
Balol field is about 13 km in length from south to north & 1 km wide. It is an unconsolidated sandstone reservoir having pay thickness is in the range of 6 to 20 m and oil viscosity in the range of 150 to 1000 cP at reservoir conditions and increasing from south to north. The process is successful in enhancing the oil recovery from envisaged 13 % of OIIP to 19 % of OIIP. However, the performance of the process was different in different sector depending on the pay thickness & the oil viscosities. The oil recovery is 54 % of OIIP in southern part of the field where thickness and oil viscosity are moderate as compared to the oil recovery of 5 % of OIIP in northern part where thickness and viscosity are high. Various attempts viz. reduction in spacing between injectors and producers through infill drilling and drilling of horizontal wells were made to improve the ISC performance in this sector but there was not much success.
To understand the reasons for poor process performance in northern part of the field conventional coring along with Side Wall Core (SWC) were carried out in a replacement air injector which was just 13 m away from the old air injector. The results of conventional core and side wall cores were correlated. As the conventional coring is cost intensive and involves complication, only SWC was carried out in another replacement air injector falling in southern part of the field which is 80 m away from the old air injector.
The conventional core & SWC of the well from northern part indicated that in thick pays the burning is taking place only in top few meters of the pay and major part of the pay is unaffected by the process. The SWC analysis in the southern part well having moderate pay thickness indicated that the entire pay participated in the burning. This indicated very good vertical sweep and oil displacement.
Air injection design is based upon the oil characteristics, fuel deposition, pay thickness, porosity etc. The core analysis indicated that in thin reservoirs vertical sweep efficiency is very high as compared to thick reservoirs. In thick reservoirs burning occurs in top few meters and any increase in air injection rate result into the early flue gas breakthrough and subsequent loss in oil production. The core data & the process performance of the various sectors of Balol field confirms that ISC process is more effective in terms of volumetric sweep and oil recovery in moderately thin reservoirs as compared to thick reservoirs and application of the process in thick reservoirs need relook while designing of the process.