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.
Khare, Sameer (Cairn Oil & Gas vertical of Vedanta Limited) | Baid, Rahul (Cairn Oil & Gas vertical of Vedanta Limited) | Prusty, Jyotsna (Cairn Oil & Gas vertical of Vedanta Limited) | Agrawal, Nitesh (Cairn Oil & Gas vertical of Vedanta Limited) | Gupta, Abhishek Kumar (Cairn Oil & Gas vertical of Vedanta Limited)
The objective of the paper is to present the methodology adopted for dual artificial system modeling in Aishwariya field– an onshore oil field located in prolific Barmer Basin, India. This paper presents a conceptual and feasibility study of combination of Jet pump (JP) and Electrical Submersible Pump (ESP) together as means of artificial lift for production enhancement in a well. It discusses the workflow to model a well producing on dual artificial lift (ESP producing in combination with Jet-Pump) via industry standard software and demonstrates the same with a successful case study.
Requirement of ESP change outs to restore/enhance well production in cases such as undersized pumps, pump head degradation requires an expensive work-over. However, an option for secondary additional lift (JP) installation along with primary lift (ESP) in completion system can eliminate the costly wok-over requirement if both lifts can operate simultaneously.
The procedure to model the dual artificial lift (JP and ESP) has two major components: a) Psuedo IPR at ESP discharge node and b) Standard JP modeling using pseudo IPR. Pseudo IPR is generated by modifying well specific IPR using ESP pump curve for a specific frequency. The down-hole ESP pump intake & discharge pressure sensors help calibrate the model accurately for further prediction.
The existing completion in the Aishwariya field is ESP completion with the option of JP installation in cases of ESP failures as contingency. Moreover, jet pump can be installed using slick line with minimum well downtime (∼ 6 hrs). Therefore, installing and operating the Jet pump above a running ESP will not only increase the drawdown but will result in production enhancement with minimal cost.
Devshali, Sagun (Oil and Natural Gas Corporation Ltd.) | Manchalwar, Vinod (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.) | Malhotra, Sanjay Kumar (Oil and Natural Gas Corporation Ltd.) | Prasad, Bulusu V.R.V. (Oil and Natural Gas Corporation Ltd.) | Yadav, Mahendra (Oil and Natural Gas Corporation Ltd.) | Kumar, Avinav (Oil and Natural Gas Corporation Ltd.) | Uniyal, Rishabh (Oil and Natural Gas Corporation Ltd.)
The paper describes the feasibility of revisiting old sands, for improving the recovery factors and enhancing production, which otherwise were already abandoned. The paper also outlines the systematic methods for predicting the onset of liquid loading in gas wells, evaluation of completions for optimization and comparison of various deliquification techniques. ONGC is operating in two gas fields in eastern and western regions in India. Earlier in both the fields, many sands had to be closed/isolated after the wells ceased to flow due to liquid loading in the absence of continuous deliquification. In order to predict liquid loading tendencies and identify opportunities for production enhancement, performance of 150 gas wells has been analyzed. To select most suitable deliquification technique for the present condition, all technically feasible methods have been evaluated and compared in order to get the maximum ultimate gas recovery possible.
After an extensive study, 3 wells were identified in the preliminary stage and SRP was selected as the most suitable Deliquification technique. Initially, two non-flowing wells, which had ceased due to liquid loading and were about to be abandoned, were selected. After SRP installation and sustained unloading of water for about 30 days, these wells started producing 12000 SCMD gas. In the third well, one of the top sands had earlier been isolated due to liquid loading and production history indicated that the isolated sand had a very good potential. Also, production from the well was declining in the current bottom operating sand as well due to liquid loading. Encouraged by the results that deliquification had yielded in the initial two gas wells, the isolated sand interval in the third well was opened again with the aim to revive production. The well was re-completed with SRP with both the reservoirs open. Before deliquification, the well was producing about 15000 SCMD gas from the bottom sand. After SRP installation and continuous deliquification, the well started producing gas at a stabilized rate of 45000 SCMD, thereby resulting in an additional gas recovery of 30000 SCMD for nearly one year as on date. The approach of putting in place continuous deliquification techniques has not only helped in enhancing production from the existing reservoirs, but has also opened up new avenues to revisit the earlier isolated / abandoned reservoirs for possible enhanced recoveries.
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.
Saluja, Vikas (Oil & Natural Gas Corporation LTD.) | Singh, Uday (Oil & Natural Gas Corporation LTD.) | Ghosh, Aninda (Oil & Natural Gas Corporation LTD.) | Prakash, Puja (Oil & Natural Gas Corporation LTD.) | Kumar, Ravendra (Oil & Natural Gas Corporation LTD.) | Verma, Rajeev (Oil & Natural Gas Corporation LTD.)
The case study demonstrated here is the innovative workflow for fault delineation technique on a 3D seismic volume in B-173A Field of Heera Panna Bassein (HPB) Sector, Western Offshore Basin, India. B-173A is located 50 kms west of Mumbai at an average water depth of about 50 m. The field was discovered in the year 1992 and it was put on production in Aug 1998. In B-173A field there are two hydrocarbon bearing zones one is gas bearing Mukta (Lower Oligocene carbonates) Formation and oil bearing Bassein (Middle to Upper Eocene Carbonates) formation.
The present study is an extended workflow on Advanced Seismic Interpretation using Spectral Decomposition and RGB Blending for Fault delineation. Iso-frequency volumes are extracted from Relative Acoustic Impedance data instead of seismic data itself.
The workflow is for effective fault delineation and it consists of Spectral Decomposition of relative acoustic impedance data and RGB Blending of discontinuity attributes of different Iso-frequency volumes.
It is observed that RGB blend volume of discontinuity attributes provided more convincing results for fault delineation as compared to the results of traditional discontinuity attributes.
Foaming in absorber column for sour gas treatment using amine is a common problem which adversely affects column performance leading to reduction in sales and fuel-gas production and solvent loss. Mostly antifoam injection has been a common method to counter the foaming, large dosage and frequent dosing of antifoam many a times aggravates the problem. This study details an alternative technique based on pressure pulse mechanism to control foaming in one of ONGC's gas sweetening plants.
One of ONGC's amine based sour gas sweetening plants faced severe foaming problem frequently. The feed rate is 200 kscm/hr and absorber column operating pressure is 51 kg/cm2. The experiment utilizes the property of surface tension which fluctuates with change in pressure of the system leading to foam collapse. The experimental procedure involved varying the sour gas feed rate, thereby creating pressure pulse inside the absorber column. Differential pressure across the column which is an indicator of foaming tendency is then monitored and controlled within 1.0 kg/cm2 and recorded for establishing effectiveness of the method.
It is observed that by providing a number of cycles of pressure pulse in the absorber, the differential pressure stabilizes gradually which indicates collapse of foam. It shows that whenever there is increase in feed, expansion of bubble takes place which provides high interfacial liquid-vapour contact. On the other hand whenever there is decrease in feed rate, compression of bubble takes place which provides low interfacial liquid-vapour contact. Surface layer surrounding the bubbles in a foam acts as a membrane or skin that can stretch or relax in response to change in pressure and gives a mechanical shock which breaks the bubble. The increase of size ultimately leads to instability and break-up of the upper surface and releases the liquid holdup. Hence by using feed rate spikes, the pressure of the bubble is pulsed to higher levels and returned to substantially the original level. This cycle continues for a selected number of times so that this pressure pulse travels through the liquid and bubbles and affects its surface tension. This results into a transition phase which in very high energy level breaks the bubble and releases the gas and decreases the liquid hold up and controls the foaming phenomenon.
This paper will gives an insight into a novel methodology of mitigating foaming problem in a sour gas treating absorber just by varying the feed rates in a controlled manner. This technique eliminates the need for injecting antifoam agents which in turn will reduce the operating expenditure of the plant. Adverse impact on environment due to excessive use of antifoam agent is also minimized.
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.) | Bansal, R (Oil and Natural Gas Corporation Ltd.) | Pawar, A S (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.)
This paper discusses a case study of one of the onshore field of ONGC where while processing well fluid, frequent surge has been observed leading to shutdown of the SDVs creating severe operational problems and loss of production. It was imperative to find out the problematic wells/lines located in clusters which contribute for surge formation and mitigation approach with minimum modifications.
A transient complex network of sixty five wells flowing with a different lift mode such as intermittent gas lift, continuous gas lift etc were developed in a dynamic multiphase flow simulator OLGA. Time cycle of each well were introduced for intermittent lift wells. Simulation study reveals pulsating transient trends of liquid flow, pressure which was matched with the real time data of the plant and hence confirms the accuracy of the model. After verifying the results, different scenarios were created to determine the causes of surge formation. After finding the cause, a low cost approach was considered for surge mitigations.
An integrated rigorous simulation was carried out in OLGA, by feeding more than 12,000 data points to obtain model match. Several scenarios were also created such as optimization of lift gas quantity, optimization of elevation and size. Trend obtained after each scenario was pulsating behaviour and it matched with the real time data appearing in the SCADA system of the field. After rigorous simulation with each scenario, it was established that the cause of surge forming wells/pipelines. Once the root cause of surge has been confirmed then quantum of liquid generated due to surge was determined. Adequacy checks of the existing separators were carried out to estimate the handling capacity of the existing separators at prevalent operating condition. After adequacy check it was found that existing separators cannot handle the surge generated in that time interval leading to cross the high-high safety level, resulting closure of shut down valve (SDV). After establishment of root cause of the surge, a low cost solution with small modification in pipelines and control system/valves was adopted to arrest the surges. It was first of its kind simulation carried out for a huge network of wells/ pipelines by feeding more than 12,000 data to analyze the surge formation cause and capture its dynamism owing to wide array of suspected causes. This will help to address the challenges of efficiently reviewing the entire pipeline network while designing new well pad/GGS and will also help to arrest surge by adopting a low cost solution wherever such situation arises.
Bordeori, Krishna (Schlumberger) | Gupta, Vaibhav (Schlumberger) | Sharma, Lovely (Schlumberger) | Narayan, Shashank (Schlumberger) | Talukdar, Dhurba (Oil India Ltd.) | Lama, Tshering (Oil India Ltd.)
Cased hole gravel pack (CHGP) is the most popular method for controlling production of formation sand in oil or gas cased hole wells. CHGP involves the packing of screen and casing annulus, and perforations to inhibit production of formation sand. Success of a CHGP depends on various factors such as perforation packing, cleanliness of completion brine, perforation strategy and minimizing drawdown. Quality of perforation packing aids in minimizing drawdown of gravel pack completions. This led to popularization of high-rate water packs (HRWPs), an evolved sand control method for cased hole wells. HRWPs involve pumping above fracture extension rate and placing gravels outside casing into the critical matrix. This paper discusses maturation process in design, execution, and evaluation methodology devised from a campaign of 16 HRWPs, which included two formation breakdown acid injections, one slim hole completion, two re-stresses and one top-off.
Naharkatiya fields of Oil India Limited, in Assam-Arakan basin are characterized with high degrees of unconsolidated formation sand. Elements of heterogeneity like formation sand ingression rate, PSD, mineralogy and well-profile in these two fields, where most of the HRWP treatments were executed, demanded case-specific pre-gravel-pack workover operations. Installation of screens and pumping of HRWP treatment presented many challenges, such as formation sand ingression, high circulation pressures, uneven slack/pull weights and issues in tool operations. All these challenges were tackled in unique ways and successful HRWP treatments were completed. A holistic approach was developed towards execution of a High Rate Water Pack treatment, by analyzing all interlinked elements such as perforations, cores, cement bond, reservoir saturation, water cut and offset well history. Post-treatment evaluation of HRWPs using bottomhole gauges identified a sequence of downhole events and potential issues during execution phase. Correlating each new HRWP candidate with learnings from previous ones allowed the operator to better plan workover steps towards execution of the sand control treatment. Contingency plans were devised to tackle issues learned from previous wells, and many were successfully tested in the campaign. Production rates and choke strategies were optimized by analysis of offset wells.
This paper presents data analysis of wells while correlating with their offsets. Post-treatment analysis has been discussed and correlations between suspected issues during execution with signatures in bottom-hole gauge data have been presented. Recommendation are further provided for drilling and completion operations. Evolution in design and execution process for case wells has been presented, which can be used as a reference literature for designing case specific sand control treatment program.
Hazarika, Simanta (Oil & Natural Gas Corporation Ltd) | Rathod, P. Ramulu (Oil & Natural Gas Corporation Ltd) | Burla, Ravishankar (Oil & Natural Gas Corporation Ltd) | Das, Gour Chandra (Oil & Natural Gas Corporation Ltd) | Rao, Bkvrl (Oil & Natural Gas Corporation Ltd) | Deuri, Budhin (Oil & Natural Gas Corporation Ltd)
Subsea flow lines in deep water are typically exposed to high pressure and low temperature conditions which can create problems due to formation of gas hydrate. The gas hydrate formed can plug the flow lines causing not only loss of production, but may also create severe safety and environmental hazard. Moreover, dissociation of these plugs may take weeks or even months. Assessment of the hydrate formation potential during both steady is therefore an essential part of field development studies.
The paper presents a case study of a gas field located in KG basin of India which was brought on production in 2018. The objective of the study was to assist the on-site team on issues related to hydrate inhibition during ongoing initial start-up operation and assess the arrival time of rich MEG in the onshore plant in view of turn down flow conditions during commissioning.
The study also demonstrates how the transient simulations helped to monitor progress, identify and respond quickly to address the challenges during initial start-up operation of the deepwater gas field in Indian east coast. It emphasizes the need for accurate estimation of rich MEG arrival time and the minimum required gas flow rate from the subsea wells to ensure timely return of rich MEG to the onshore plant in order to avoid disruption in hydrate inhibition in the subsea system.