PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
A hydrocarbon find has always been an exploration geologist’s adventure and has remained at the forefront of the E&P cycle for the survival of the oil and gas industry. Big and easy finds are a distant past; therefore, the quest has shifted to go beyond conventional sandstones and carbonates to more complex areas of unconventionals: low porosity, low permeability, low resistivity, tight and ultra-tight, HPHT, shale, CBM, gas hydrates, and any other possible regime including deeper, geologically complex, and seismically opaque features such as salt, basalt, sub-basalt, even basement.
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.
Nagar, Ankesh (Cairn Oil & Gas – Vedanta Limited) | Dangwal, Gaurav (Cairn Oil & Gas – Vedanta Limited) | Maniar, Chintan (Cairn Oil & Gas – Vedanta Limited) | Bhad, Nitin (Cairn Oil & Gas – Vedanta Limited) | Goyal, Ishank (Cairn Oil & Gas – Vedanta Limited) | Pandey, Nimish (Cairn Oil & Gas – Vedanta Limited) | Parashar, Arunabh (Cairn Oil & Gas – Vedanta Limited) | Tiwari, Shobhit (Cairn Oil & Gas – Vedanta Limited)
The Mangala, Aishwaya & Bhagyam (MBA) fields are the largest discovered group of oil fields in Barmer Basin, Rajasthan, India. The fields contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. The fields have undergone pattern as well as peripheral water injection. In order to overcome adverse mobility ratio and improve sweep efficiency thereby increasing oil recovery, chemical EOR has been evaluated for implementation in these fields. The potential benefits from chemical enhanced oil recovery (EOR) had been recognized from early in the field development. Polymer flooding was identified for early implementation, which would be followed by stage wise implementation of Alkaline-Surfactant-Polymer (ASP) injection in fields like Mangala. Since the commencement of polymer injection, the Mangala field polymer injectors have displayed multiple injectivity issues. In addition, the Aishwarya and Bhagyam fields are dealing with low Void Replacement Ratios (VRR) for their ongoing water injection, which if not rectified could adversely affect recovery. While various types of injector stimulations are being used, injectivity increases are short lived. A new technique termed as ‘Sand Scouring’ has been successfully applied resuting in sustainable injectivity gains.
The technique involves pumping creating a small fracture with a pad injected above fracturing pressure and then scouring the fracture face with low concentration 20/40 sand slugs in range of 0.5 to 1 PPA 20/40. The treatments are pumped at the highest achievable rates with the available pumping equipment within the completion pressure limitations. Based upon the available tankage, the scheduled is designed such that pumping of a fixed volume of sand stage, a quick shut-down allows for mixing the next stage of slurry. The pumping schedule and a ‘scouring’ intent is deliberately designed to avoid requirement of fracturing equipment, related cleanout equipment and resulting costs. The challenge of conformance is addressed by designing the pumping schedule to incorporate stages of particulate diverters and validated using pre and post injection logging surveys. .
Sand scouring jobs in 16 wells have been conducted across Mangala, Bhagyam & Aishwarya injectors. Out of thesewells, 9 wells had zero injectivity while the other 7 required both injectivity and conformance improvement. Most of the treated wells resulted in multifold improvement of injectivity as compared to their prior injection parameters. Sand scouring resulted in sustained injection performance when compared with prior conventional methods of stimulation. Injectivity improvements from sand scouring lasted for an average of 3 months days as compared to 14 days for the conventional stimulations. Sand scouring evolution, design, results and plans for future improvement are all discussed in this paper.
Varma, Nakul (Cairn Oil & Gas, Vedanta Ltd) | Nagar, Ankesh (Cairn Oil & Gas, Vedanta Ltd) | Manish, Kumar (Cairn Oil & Gas, Vedanta Ltd) | Srivastav, Pranay (Cairn Oil & Gas, Vedanta Ltd) | Nekkanti, Satish (Cairn Oil & Gas, Vedanta Ltd) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd) | Srivastav, Preyas (Cairn Oil & Gas, Vedanta Ltd)
This paper describes simulation solution for CT(Coil Tubing) based WBCO in flowing ESP/Jet Pump wells for scale/polymer debris deposition removal prior to any treatment in well, such as – Formation stimulation, ESP treatment, etc. It also describes prediction for requirement of Surface Well Test spread support to assist Nitrogen assisted WBCO. The paper describes new way of simulation for CT WBCO job in artificially flowing wells to predict decreased Liquid rate from reservoir, CT pressure & friction pressure losses. The modelling is done in Prosper and Cerberus, the results of which are validated with surface well test and Multiphase flow meter data recorded during the jobs. The results observed were very close to modelled with a number of advantages such as – No loss returns, higher lifting velocities, prediction of increased/decreased reservoir liquid rate affecting Motor winding temperature in ESPs, no settling of debris, post job Increased Liquid gain from well, decreased tubing friction pressure loss
Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO2 content in reservoir fluid. A procedure was developed earlier to model the impact of reservoir CO2 on waterflood, polymer flood and ASP flood (
The objective of this work was to validate the modelling procedure developed to predict the produced gas rate in such a system with very high amount of CO2 in reservoir fluid.
A live oil coreflood experiment was carried out using 12 inches long Bentheimer core under Aishwariya reservoir pressure and temperature conditions. After saturating the core with live oil, the core was water flooded with brine for ~3.7 pore volumes. Produced gas volume was measured at different times so as to generate gas production profile.
Two different simulation techniques were used to simulate the experiment and match the gas production profile. First technique was using a compositional simulator with EOS based PVT while the other technique was using an "advanced processes simulator" modeling the component distributions based on partitioning coefficients. Both methods could successfully capture the production of gas from both liquid streams; oil and water and a reasonable match for the produced gas could be obtained.
The approach developed to simulate impact of CO2 on different aqueous based flooding processes in Aishwariya field was validated by matching the coreflood experiment carried out under actual Aishwariya reservoir conditions. It helped to confirm confidence in performance prediction of aqueous based flooding mechanisms planned in Aishwariya field despite the presence of significant amount of CO2.
The paper presents history match of unconventional produced gas profile of a coreflood carried out under Aishwariya field conditions with very high amount of dissolved CO2. The proposed method can be applied to estimate produced gas rate in other fields with very high amount of CO2 in reservoir fluid.
The Rajasthan Field has been undergoing waterflood with produced water reinjection (PWRI) using makeup water with a moderate sulfate (≈500 mg/L) and negligible organic content since 2010. Initial analyses of the formation water indicated that the volatile fatty acid (VFA) content was quite low (≈ 20 mg/L), suggesting
The mechanistic reservoir souring model considers H2S biogeneration due to water-soluble VFAs and/or primarily oil-soluble organics such as BTEX components, the effects of H2S-siderite geochemical reactions within the reservoir to scavenge H2S, flow of H2S (and other components) through the reservoir to the surface, and partitioning of H2S into the oil, water and gas phases within the reservoir and in the surface separators. Also included in the Rajasthan model were the use of power water to lift the well production since it affects partitioning at the surface; and, the effect of chemical H2S scavengers added in selected well flowlines to maintain H2S partial pressures at safe levels.
The model determined that the observed H2S production was not possible even with complete consumption of the indigenous VFAs by sulfate-reducing bacteria and that only with the majority of their organic nutrients being provided by the BTEX-type components were the historical H2S production levels able to be matched. The model results have indicated that H2S production rates have already peaked in the field, primarily due to the reduction in makeup water which provides most of the sulfate being injected into the reservoir. Sulfate is the limiting microbial reactant since the oil-soluble organic supply is essentially infinite.
This study has shown even in non-seawater waterfloods and with minimal organic acids in the formation water that reservoir souring can occur, resulting in the need to handle significant levels of H2S on the surface. The significance of oil-soluble organics as a potential SRB nutrient must be considered when planning a waterflood if sulfate is injected.
Oil, water and gas separation at wellpads with improved technology and compact design has significant advantage for increasing liquid handling from group gathering wellpads and accelerating oil production from fields. Cairn, Oil & Gas vertical of Vedanta Limited is the Operator of RJ/ON block in India with major fields Mangala (M), Bhagyam (B) and Aishwariya (A). Mangala field (75% of MBA production) is the largest onshore oil discovery in India and Bhagyam-Aishwarya fields together contribute to ~25% of the total MBA production. The MBA fields are on water + polymer flood and gradual increase in water production is challenging to process the same oil production volumes. Future field development plans in these fields requires debottlenecking of liquid handling constraints.
The current paper depicts the fast track modifications planned in various fields and its implementation carried out in Aishwariya field which was limited for produced fluid handling due to capacity constraints at the centralized processing well-pad 8 (AWP-08). These modifications were aimed towards localized produced water treatment and reinjection of 30,000 barrels per day (bpd) into the existing injection manifold at Aishwarya Wellpad. In the first stage, produced water is separated from 3,000 ppm to 300 ppm OIW and in second stage from 300 to <100 ppm OIW with <5 ppm TSS. The existing vessels were retrofitted and modified in field with internals like inlet device, calming baffles, coalescing pack, overflow weir and oil bucket. This enabled additional residence time suiting the given fluid characteristics and efficient separation of the produced fluids. This resulted in accelerating oil production from the field by ~2,000 bopd by opening more shut-in wells and leveraging terminal liquid handling capacity. And with the future ESP upsizing and more infill wells coming online, there is further potential to gain additional oil upto 3000 bopd. The execution of Project commenced in Sep-17 and was commissioned in Dec-17 in a record 3 months’ time period including engineering which helped in monetizing early oil production benefit. Based on the success of the local pad separation in Aishwariya field, similar scheme is planned to be implemented in Mangala & Bhagyam wellpads and other small fields with high water production.
Pal, Arindam (Cairn India Limited) | Chowdhury, Manabesh (Cairn India Limited) | Phinney, Eric (Cairn India Limited) | Das, Amlan (Cairn India Limited) | Dwivedi, Nikhilesh (Cairn India Limited) | Lobo, Kenneth (Schlumberger Asia Services Limited)
Barmer Hill is a low permeability lacustrine reservoir complex of Paleocene-Eocene age deposited in Barmer Basin, North West India. In Mangala-Aishwariya area, this reservoir consists of laminated, high porosity (25-35%), low permeability (~0.2-4 mD) porcellanites of biogenic origin. Commercial development of analogue low permeability reservoirs are carried out with multi-stage hydraulic fracturing in horizontal wells. This paper outlines the planning to execution of three
Mangala and Aishwariya fields are tilted fault blocks with 3-way fault closure bound by a major down-to-the-west normal fault. The structural complexity is exacerbated by a series of cuspate, low angle listric faults in the Barmer Hill Formation. The gravity faulted area is structurally complex and seismic imaging is challenging. Downdip towards the east, the Barmer Hill Formation is well imaged and the units gently dip (2o −10o) south-east.
Detailed reservoir characterization work is carried out before horizontal well planning in the structurally complex tight reservoirs of Barmer Hill. Transverse and longitudinal horizontal wells are designed along the principal stress directions to prove the
Drilling with a three casing policy in Barmer Hill, the 8-1/2" intermediate section of the well is landed right below the top of target reservoir at an optimum inclination. In 6" drainhole section, the inclination is either built-up or dropped to align the trajectory with the formation dip appropriately. The well azimuth is primarily guided by the regional understanding of principal stress directions and collision constraints. The drainhole section is geo-steered through the target reservoir with a state-of-art bed boundary mapping tool.
In Barmer Hill, Well-1, a transverse
Pal, Arindam (Cairn India Limited) | Nazhri, Ahmad (Cairn India Limited) | Phinney, Eric (Cairn India Limited) | Sunder, V. (Cairn India Limited) | Goodlad, Stephen (Cairn India Limited) | Dwivedi, Nikhilesh (Cairn India Limited)
Complicated structural relationships within gravity collapse, growth fault and thrust regimes have always been challenging while modelling with conventional
In the extensional Barmer Basin, north-western India, the Barmer Hill Formation of Paleocene-Eocene age is affected by syn-sedimentary faulting events. Gravity collapse structures developed synthetically along a down-to-the-west major boundary fault are expressed as a series of cuspate, low angle listric faults. Seismically mapped, depth converted conjugate faults and horizons are sequentially modelled as geological events using a pillarless structural framework algorithm within the volume of interest. The gravity collapse structure bound by main boundary fault and several λ and Y-shaped listric faults are accurately modelled using the fault framework modelling process. The conformable Barmer Hill horizon inputs are well tied, converted to point datasets, filtered with suitable fault cut-backs and modelled using horizon modelling process. The algorithm uses an interpolation technique that creates triangulated meshes for modelled surfaces ensuring high degree of data consistency, retaining complex truncation relationships in the model. Residual calculation of the structural framework shows excellent coherence with input dataset.
Structural framework modelling is followed by structural gridding performed at an optimum resolution to capture the reservoir heterogeneities. Depending on the end usage and fault complexity required in the model, multiple realizations of geological and simulation grids are created. The layering scheme is optimized with an integrated approach, honoring reservoir heterogeneity and simulation constraints. The structural grid is quality checked with parameters like negative volumes, distorted - isolated cells and cell width. By virtue of grid orthogonality, significant improvement is observed in simulation run time.