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.
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.
An Under Balanced Drilling (UBD) pilot project in the Heera and Mumbai High fields of Western offshore India was recently completed successfully. The objective of the project was to establish whether the technology can improve productivity performance in the reservoir section, avoid reservoir damage and thereby enhance oil production from the wells. This paper incorporates the drilling experiences and challenges faced during execution of this pilot project, the well design considerations and methodology, evaluation of the drilling fluid systems and also describes the tangible benefits of using this technology in the drilling of these sections and wells. In terms of the productivity gains from drilling these wells using UBD technology, through the sub-hydrostatic formations offshore Mumbai, the results were very positive. With the success and encouraging results from the pilot project, more wells are now planned, including wells in the losses-prone and depleted Mumbai High and Neelam fields, to incorporate the experiences of the learning curve.
Thapliyal, Anil (Oil and Natural Gas Corporation Ltd.) | Kundu, Sudeb (Oil and Natural Gas Corporation Ltd.) | Chowdhury, Suparna (Oil and Natural Gas Corporation Ltd.) | Singh, Deepika (Oil and Natural Gas Corporation Ltd.) | Singh, Harjinder (Oil and Natural Gas Corporation Ltd.)
Pressure maintenance by gas injection in gas cap is one of the well-established methods for improving the ultimate recovery. Gas injection in the crestal part of reservoir into the primary or secondary gas cap for pressure maintenance is generally used in reservoirs with thick oil columns and good vertical permeability and this process is called gravity drainage. This paper comprises methodology and results of study to evaluate the feasibility of gas injection in gas cap for maintenance of reservoir pressure and to envisage incremental oil gain of a mature offshore carbonate field located in western offshore of India.
Field has already produced more than 30% oil of its initial inplace volume. Water injection was started after 4 years of production and currently field is producing oil with 90% water cut. After one year of initial production phase the field producing GOR rose to two to three fold of its initial value mainly due to contribution of gas from gas cap. Depletion of gas cap gas made significant adverse impact on reservoir pressure and also fast pressure depletion from crestal part had allowed water breakthrough of injection and aquifer water to oil producers. At this stage to reduce the decline rate of wells for maximizing the future recovery without drilling of new wells and also without extension of existing infrastructure, the injection of gas in depleted small gas cap have been studied.
In order to evaluate the feasibility of gas injection in depleted gas cap and its overall impact on oil recovery, three aspects were seen. First the optimized quantity of gas injection and its sensitivity along with the number of gas injectors were decided through reservoir simulation. Therefore, suboptimal oil producers falling within gas cap area are chosen for conversion to Gas injectors. Secondly injection gas requirement for the process will be fulfilled partly through the recycling of produced gas and rest from free gas production from another pay of the same field. Finally it is examined that current existing facility of gas compression will sufficiently cater the additional requirement of gas compression. The process will have additional 10 to 11% contribution in future oil production.
The process of charging gas cap will provide additional support over ongoing water injection leading to a significant additional oil recovery by reducing the oil decline rate.
The Kreuz Glorious has accommodation for 304 people and an eight-point mooring system. It will be deployed for a 2-year project in the Arabian sea for ONGC. Kreuz Subsea and Seamec have successfully completed the mobilization of the Kreuz Glorious vessel as part of a 2-year project with India’s Oil and Natural Gas Corporation (ONGC). The scope of work includes the inspection of 27 offshore jackets in the Mumbai High North, Mumbai High South, Heera, Neelam, and Bassien assets located off the coast of Mumbai in the Arabian Sea. The Kreuz Glorious has a 1200-m2 deck area, with accommodation for 304 people and an eight-point mooring system.
This paper describes an efficient approach to implement IAOM project and evaluate subsurface well performance and surface network facilities of a supergiant oil field flowing from multilayered carbonate reservoirs. The field is produced via several gathering stations and pumping stations. The current manifold pressures at the RDS stations are high, which will increase by the introduction of gas lift and by the additional production from new wells. In IAOM implementation process, individual well strings and robust network model was built for the asset on the IAOM platform. This model was further utilized in meeting various production optimization challenges such as well surveillance, production and Injection optimization, forecasting and allocation and field development planning. This paper demonstrates how IAOM project was used to run different production optimization scenarios, describing the objective, methodology, analysis and results to address various challenges in production optimization.
This project focuses on building a reservoir sub-sea network model for a condensate field in the gulf of Guinea, the Duke Field. It integrates the five developed Duke reservoirs, development wells and subsea network using the Petroleum Experts' Integrated Production Model suite of software, (IPM) which is widely used in the E&P industry especially for integrated forecasting, surveillance and production system optimization that require integration of surface and subsurface models. Following the acquisition and quality control of data from other teams working on the Duke Field, a network model which integrates the five Duke reservoirs, their associated wells and subsea network up to the production separator was built. The model was initialized and used to predict full field performance under different scenarios. Finally, a water injection allocation sensitivity study was performed and the results were analyzed both technically and economically. From the technical point of view, the option to reallocate 10 kbwpd from reservoir U to reservoir P-upper North and another 10 kbwpd from Reservoir ST to reservoir Q-Lower brought about the optimum recovery. This was also supported by a simple economic analysis. It was then recommended that additional water injectors be drilled in P-Upper North and Q-Lower to unlock an additional 8.4 MMSTB of reserves resulting from higher sweep efficiencies and better pressure maintenance.
Xinggang, Han (PetroChina Changqing Oilfield Co.) | Hui, Wang (PetroChina Changqing Oilfield Co.) | Pengxin, Feng (PetroChina Changqing Oilfield Co.) | Wenlong, Xu (PetroChina Changqing Oilfield Co.) | Xiaorong, Wang (PetroChina Changqing Oilfield Co.) | Haibin, Ma (PetroChina Changqing Oilfield Co.) | McBride, Steve (Weatherford Intl., Malaysia)
The gathering system in the Sulige gas field is characterized by "simultaneous metering of gas with liquids?? and by "multiple inter-connections between wells??. With the large scale expansion of the gas field, the gathering and transportation system has become so complex that it is increasingly difficult to optimize the production of each well or gas source in an integrated manner and simultaneously eliminate pressure bottlenecks in the network. Traditional optimization methods can handle simulations and process calculations for single wells or small local networks, but cannot adequately address the overall system performance as a whole.
Consequently, integrated optimization technology has been introduced in the Sulige Gas Field. A compositional model of the entire gas field has been constructed of individual production components, and via comparison of simulation results and measured data, the model has been accurately tuned. Based on the calculated results of the tuned model, several conclusions have been derived which collectively support the field production target of 40 Million m3 per day, representing an increase of 14% per day. These measures include the laying of a new pipeline to relieve pressure bottlenecks, adjustment and optimization of the compressors? operational parameters in the processing plant, and choke setting optimization in specific areas. Results clearly demonstrate that the application of optimization technology in the complex infrastructure of the Sulige Gas Field has been successful, and furthermore that it can ensure the gas gathering and transportation system operate in both a stable and efficient manner.
Using practical field data and reference case studies, this paper highlights the positive effects of the optimization process via for example pressure data matching, pressure bottleneck reduction and/or elimination, and compression scenario optimization. The application of optimization technology has provided the end-users with both accurate and reliable results which in turn contribute to improved decision making for the field production and development planning. Moreover it establishes a new management model for the large-scale gas field production system such that any modifications are closely associated to calculated simulation results and are supported by an outlook of maximizing production revenues.
A giant onshore field producing from multilayered undersaturated carbonate reservoir presents many challenges. The field is producing since early seventies supported with peripheral water injection leading to wide variation in reservoir pressure and water cuts. The field has been produced with the help of 6 gathering manifolds. The northern manifold presents additional challenges as this area is affected with asphaltenes deposition problems in production tubing and flow lines. Tubing obstruction due to asphaltenes adversely affects flow basides cause difficulty in lowering pressure gauges resulting into scarcity of pressure survey data. Additionally, some wells are operating on gas lift and a gas injection pilot is located on the western side leading to Gas Oil Ratio (GOR) variations. The horizontal wells completed in the low permeability layer tend to cease production as the water cut reaches >35%. Production allocation, optimization and de-bottlenecking become difficult in such a scenario. It was, therefore, decided to build a production network model as a tool to overcome such problems. This paper presents the process of preparing the production network model. Tuning PVT properties for the field is described with reference to pressure traverse correlations. Well model calibration with paucity of pressure survey data was achieved with good agreement with production history. Production from each well at different choke setting, water cut and reservoir pressure was estimated and compared with field data. Proper tubing size selection would allow stable flow in the tubing even at high water cut differing gas lift implementation for many years. Production network model is a necessary tool for production and reservoir engineers for optimization, de-bottlenecking and potential estimation.
Bartos, Scott Charles (U.S. EPA - Climate Change Div.) | Chakraborty, Ashok Baran (Oil & Natural Gas Corp. Ltd.) | Hauswald, Edward C. (ICF International) | Seastream, Sandy (ICF International) | Shartzer, Andrew (ICF International)
Directly supporting the Global Methane Initiative (GMI), the Natural Gas STAR International Program is a voluntary partnership between the oil and natural gas industry and the United States Environmental Protection Agency (EPA) that promotes use of cost-effective technologies and practices to reduce methane emissions. In 2008 and 2009, the Oil and Natural Gas Corporation LTD (ONGC), the first Natural Gas STAR International Partner in India, undertook a desktop review and in-country methane emissions measurement study and analysis to identify and quantify baseline methane emissions levels for seven of its production, processing and transmission facilities. The measurement study was conducted using infrared camera technology to identify emission sources; and a combination of turbine meters, high volume samplers, and calibrated bagging techniques to measure their emission rates.
This paper details the survey activities and quantitative measurements for the seven surveyed facilities. EPA's Natural Gas STAR International (NGSI) Partners are eligible to receive recommendations on technologies or practices, a facility-specific assessment of their technical feasibility, anticipated methane emission reductions, and the economic and environmental value of the proposed emission reductions. The paper further describes mitigation projects ONGC has deployed as a result of their collaboration with EPA.
ONGC, acting immediately upon the Partnership's recommendations, and consistent with ONGC's corporate carbon management program, have to date reduced methane emissions in the studied facilities by 30 percent, achieving annual natural gas savings of more than 9 million cubic meters (MMcm). This paper also reviews ONGC's future climate protection plans.