Pandey, Ajeet Kumar (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Kumar, Vishwa (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Bharsakle, Anuradha (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Vasudevan, K. (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited) | Singh, Dhruvendra (Geodata Processing and Interpretation Centre, Oil and Natural Gas Corporation Limited)
Quantification of uncertainty in input parameters to build a robust 3D geological model is an integral and perhaps the most crucial requirement in high-risk exploration areas. This demands more innovative and effective management of uncertainties for optimizing reserve portfolios and better formulation of exploration and exploitation strategies for oil and gas fields. The present area of study pertains to Mumbai/Western Offshore Basin of India. The reservoirs of the study area are challenging due to their high spatio-temporal heterogeneity and discrete fluid distribution. Wells drilled during the field development plan are devoid of hydrocarbon from the lower zone of the reservoir (Middle Eocene/lower Bassein pay) while upper zone (Late Eocene/upper Bassein pay) produced significant amount of gas despite same lithological composition and structural setup, which reduced the utility of pressure-performance based or conventional modeling approach as it couldn't explain the complex geological set up of the deposition.
In this background, a thorough evaluation of critical aspect of most complex and anisotropic carbonate reservoir of Bassein Formation of Middle to Late Eocene age has been taken up to delineate the trends of favorable locales in the area. Inputs from micro-facies analysis, fluid transmissibility of Formations and diagenetic imprint analysis were considered to start the present study. An integrated methodology was designed incorporating seismic, well/logs, core samples, sedimentological, bio-stratigraphic & reservoir data to estimate petrophysical properties and necessary modifications in conventional approach were introduced for capturing the reservoir heterogeneity and stochasticity. Hi-frequency digenetic cycle mapping at log scale and pre-stack inversion results (P & S impedance, Vp/Vs ratio) were incorporated to build a robust geo cellular model and characterize the reservoir.
Uncertainty analysis presented in this study is mainly focused on structural and petrophysical parameters. The effect of each parameter/factor and their interaction effect (response) with other parameters are analyzed through Optimization Algorithms, to quantify the uncertainties and its impact on reservoir characterization. Sensitivity analysis indicated that Oil Initially In Place (OIIP) exhibits significant sensitivity to effective porosity and water saturation. Therefore, distribution pattern of these uncertainty parameters are derived from Probability Density Function (PDF) and used to restrict the variability of the volumetric estimates to retain the P10/P90 ratios within the acceptable ranges.
Quantification of structural parameter was performed using non-linear multiple regression technique, constrained by statistically Maximum Allowable Error (+Standard Deviation).
Present analysis enabled us to reduce the uncertainty associated with various reservoir characterization elements. Further, it enhanced robustness of velocity modeling, petrophysical and lithological interpretation through determination of uncertainties with high degree of accuracy and provided their role in estimation of final hydrocarbon-in-place volumes. The parameterization of the uncertainties deliberated could be used as a template in other fields sharing similar structural and depositional characteristics to mitigate the risks associated with Field Development Plan.
A well in the Panna-Mukta-Tapti Joint Venture (PMT JV) was completed using an isolation valve as the method of isolating the reservoir whilst running the completion into the well. Mechanical failure to open the valve was not anticipated as the isolation valve had a successful history in the JV with no failures in the last 10 years. However, in this well, the isolation valve failed to open. After spending multiple days attempting to open the valve and diagnosing the cause of the failure, it was concluded that the isolation valve was mechanically stuck.
Further evaluatios of solutions incorporating Coil tubing (CT) and e-line interventions concluded that standard milling operations would pose additional challenges for the well due to the design of the completion below the isolation valve. Subsequently, a unique, star shaped milling bit was designed and manufactured to enable milling of the isolation which was smaller than 2.56" SSD and landing nipple present below the isolation valve. This was required to ensure future access for interventions through the SSD and landing nipples is not compromised and milling out the coupon from the flapper isolation valve does not get stuck in the smaller ID completion profile below it.
The newly designed bit enabled milling and subsequently expanding that hole to the desired OD of 2.7" which would allow for future interventions. E-line milling was selected due to limitations in control with CT for debris generated. The total time from identification of the problem to designing, manufacturing, testing the new bit, transporting it to India and executing the solution was 45 days. The operation itself was carried out within 45 hours vs 120 hours projected with CT, leading to a significant cost saving, equivalent of 3 times daily spread rate for the rig. This unique methodology also enabled early onset of production, avoiding a delay of approxmately three month.
This was the first time this new mill bit was applied and the first time that this isolation valve had been milled out using E-line. Existing, standard bit designs were not sufficient to accomplish this solution nor were conventional approaches satisfactory in today's economic climate. This paper will present the significant benefits accomplished from the utilization of the robotic, electric-line (e-line) intervention to mill out a malfunctioning isolation valve versus the use of coiled tubing (CT).
In addition, it will use the flexibility and control features of e-line based, intervention technology towards addressing short lead time and design modification required to meet dynamic well challenges.
Thapliyal, Anil (Oil and Natural Gas Corporation Ltd.) | Kundu, Sudeb (Oil and Natural Gas Corporation Ltd.) | Dimri, Sunil Kumar (Oil and Natural Gas Corporation Ltd.) | Dutt, Ankit (Schlumberger) | Mishra, Shubham (Schlumberger) | Aggarwal, Akshay (Schlumberger) | Agarwal, Ankit (Schlumberger) | Ojha, Aditya (Schlumberger) | Bradley, David (Schlumberger) | Giddins, Marie Ann (Schlumberger)
For planning the operations of Oil and Natural Gas Corporation Limited (ONGC) in the complex Heera field, it was estimated that over one hundred simulation runs would be needed to complete the history match of the field and almost the same number of simulations would be needed for production forecasting. Heera is a large field, with multiple faults and seven stacked carbonate formations. There are significant variations in petrophysical properties, and variable degrees of communication between reservoir zones. The simulation models include 479 wells with commingled production or injection. Well trajectories are complex and include multilateral and horizontal configurations. Field development options include use of simultaneous water alternating gas (SWAG) for enhanced oil recovery.
Combining all these features, it would be difficult to run all the necessary sensitivity cases within the required project timeline, using a conventional reservoir simulator. Therefore, it was decided to test the applicability of a new generation simulation tool to address the challenges of the study.
To ensure that the change of simulator would not impact the integrity of the model, rigorous quality checks were performed on the input data. After successful evaluation, the new software was used for the reservoir engineering study.
The decision to apply the new simulator significantly reduced the elapsed time, with some realizations over 20 times faster compared to the original base case. As a result of this speed-up, numerous runs could be carried out to refine the history match. Multiple sensitivities could be used to help understand and reduce the uncertainties in a more comprehensive manner. Moreover, the prediction cases could be optimized to identify the best recovery strategy.
This study has demonstrated the value of reducing simulation run times, to complete the project with greater efficiency and more confidence in the results. In future studies, high performance software tools can also enable use of fine resolution models, to capture detailed heterogeneities and optimize areal and vertical sweep.
Yong, Li (Research Institute of Petroleum Exploration and Development PetroChina) | Baozhu, Li (Research Institute of Petroleum Exploration and Development PetroChina) | Jiasheng, Zhou (China National Oil and Gas Exploration and Development Corporation, PetroChina)
M1 reservoir is a large multi-layered sandstone reservoir in Middle East, which is under primary depletion and edge aquifer drive. There are lots of sources of water production data in M1, and water production data are one of the most important and invaluable surveillance data to understand reservoir connectivity. This paper proposes a method to show how to integrate all sources of aquifer influx surveillance data to evaluate reservoir connectivity of M1.
There are four types of aquifer influx identification data in M1 reservoir, and different type of surveillance data are analyzed in detail. Through aquifer influx analysis, it can be confirmed if wells are aquifer flooded in some zones. Then, combined geological understanding with well aquifer breakthrough time and well water cut change characteristic analysis, the possible aquifer influx zone is determined. Finally, aquifer support and sand body connectivity around water flooded wells are better understood, which is helpful and useful for next waterflooding development.
M1 reservoir is a large multi-layered sandstone reservoir of deltaic environment with oil bearing area around 500Km2 in Middle East. And M1 is influenced by fluvial, tide and wave, which results in great variations of sand bodies' distribution, reservoir quality and connectivity. Furthermore, M1 reservoir is still under primary depletion with reservoir pressure close to saturation pressure, so waterflooding should be applied urgently. Four types of data were analyzed to study the aquifer influx, which including measured water cut data, flowtest data, saturation logging data and SGS data. Through data analysis, the confirmed aquifer-influx wells and possible aquifer -influx wells are determined, and water breakthrough time and water cut change characteristic are also determined. And based on the characteristic, four areas with different characteristic are classified. Combined with the geological understanding, it is found that the connectivity within each area are similar, but there are barriers among different areas which results in poor communication among different areas. Also the water breakthrough zone of each area are different, and it is useful to understanding aquifer support and reservoir lateral heterogeneity of different zones. Furthermore, aquifer influx has preferred direction, which mainly moves along with the channels axis. This phenomenon should be considered in well pattern decision making during the following waterflooding study.
This paper offers a case study of reservoir connectivity analysis based on different types of aquifer influx surveillance data analysis. And the understanding is also much valuable and useful for depositional facies mapping and the next waterflooding well pattern selection and decision. It also provide a reference for the related study on other similar field.
Worldwide excessive water production in gas reservoirs has always been regarded as one of the most formidable problems, which hampers the productivity of the well to any extent and in the extreme cases may lead to ceasure of the well due to water loading although the reservoir contains sufficient amount of recoverable reserves. The source of water production can be a channel behind casing due to poor cementation, casing leaks, coning, encroachment, water breakthrough and flow through natural and induced fractures. In the process of shutting off /mitigation of unwanted water production, the identification of source of water inflow in the well is the most important step for choosing a correct technique. However, the problem becomes even more complex if multiple mechanisms of water invasion are simultaneously active in the well.
There are various mechanical and chemical techniques to deal with excessive water production. The mechanical means provide a seal in the near-wellbore openings. However, most of the time, it is desirable to achieve matrix or small fissure penetration of the sealing material. Among the chemical methods, polymer gels are considered as one of the most commonly applied technique on account of relatively low cost, ease of pumping and ability to penetrate deeper into the reservoir.
Bassein is a major gas field in the western offshore basin of India and is producing gas since 1988. The entire structure of the field is a gas cap gas reservoir, which is underlain by very thin oil column and large aquifer and producing gas under partial aquifer drive. The field recovery has crossed 60% of GIIP and presently most of the wells of BC and BE platforms are either producing large amount of water or have ceased to flow due to water loading leading to huge loss of well productivity and making them suitable candidates for water-shut-off treatments. The well BC-2, which was/ had ceased to flow due to water loading, but could not be brought back on production even after mechanical water shut off method was chosen as a pilot well for treatment with deep penetrating high temperature resistant gel system. After gel treatment, the well was put on sustained production along with reduction in water production by 90%.
This paper discusses the laboratory studies for polymeric gel optimization, methodology of job design with operation sequence and results obtained from the field.
Mahato, P K (Well Stimulation Services, Oil & Natural Gas Corporation Ltd., Chandkheda Campus) | Raj, Prithvi (Well Stimulation Services, Oil & Natural Gas Corporation Ltd., Chandkheda Campus) | Bahuguna, V K (Well Stimulation Services, Oil & Natural Gas Corporation Ltd., Chandkheda Campus)
Severe fluid loss problems was experienced in Mumbai High and Bassein lime stone in Neelam, mainly due to pressure depletion consequent to sustained production from the layers. Loss problem in producing zones are presently being controlled with imported pills which contain some solid materials and poses multiple problems during work over operations like retrieval of packer etc. WSS Ahmedabad has made an in-house efforts to develop a solid free pill which can develop high viscosity in the producing zone and form a plug like structure to prevent losses and having thermal stability for minimum 120 hrs or till work-over job completed at 120°C and no residue after the job
Fresh cross linked gel was prepared by using various additives as per the field conditions and stability of the cross linked gel was optimized. Using HPHT filter press, the wall building coefficient ‘Cw’ and spurt loss ‘Vsp’ were calculated for cross linked polymer under different conditions. Disintegration of cross linked gel with different concentration of HCl, acetic acid & suitable gel breakers were optimized. Series of experiments were carried out for delay time v/s thermal stability for proper placement of pill at target zone.
The clean pill has been designed with available indigenous chemicals and biodegradable polymer. The pill develops high viscosity in the thief zone and forms a plug like structure. The crosslinking of the plug can be controlled by optimizing the dosage of delaying agents to allow for its easy placement. The designed cross linked pill may be self-degraded after 6-7 days at reservoir temperature. Pill can also be easily disintegrated in mild HCl. (if required) and can be flowed back after the completion of work over job, without damaging the producing zone
The X-linked polymer plug is dependable well control method for safely isolating the producing zone during well service operations. The X-linked polymer plug so developed is envisaged for its field trial. The paper describes the results of intensive lab studies and execution methodology for the development of a solid free, thermostable, biodegradable X-linked polymer plug which can be used as temporary isolation in Mumbai offshore. The newly developed polymer plug may prove to be an indigenous & cost effective thermosetting polymer plugs. the successful field trial will be extremely beneficial for isolating the thief zones in lime stone reservoirs where this phenomenon is very common and different type of products by different companies have tried with mixed results
Panna field is located in the western offshore region of India and produces oil and gas from Middle Eocene and Early Oligocene Bassein limestone. Production is taken mostly through 3 ½" or 4 ½" tubing through a packer set in 7″ liner. The Panna-Mukta-Tapti Joint Venture (PMT JV) took up a plan to revive wells addressing well integrity issues and limitations associated with old completion jewelry for increasing the production.
Work-over campaign was planned for four wells on PB and three wells on PC platform to enhance production. The plan was to cut and retrieve the old completion and tubing above the 7″ permanent packer and install improved completion, having facilities of Permanent Down Hole Gauges (PDHG), Gas Lift Mandrel (GLM) and Chemical Injection Mandrel (CIM) through an additional packer set in 9-5/8″ casing.
In line with two barrier philosophy, two plugs were set inside the production tubing, one at TRSSV (shallow-set) and another one below the production packer (deep-set). The plug below the production packer doubled-up to also hold back the workover fluid, which may have hampered the productivity of an already sub-hydrostatic reservoir, if losses occurred. However, at the end of workover operations, the retrieval of this deep set plug could not be done even after various attempts and spending valuable rig time. This problem was faced with three out of the first four wells, which proved to be a challenge and forced the team to devise a new strategy for remaining wells.
At this point, an ingenious solution was devised to employ Plasma Based Punctures (PBP) to puncture the tubing in the limited space between the packer and the deep set plug to kick back the wells into production. Rig based PBP operations were carried out on two PC wells and Rig less PBP operations were carried out on three PB wells to get them online post work over operation. This resulted in saving several hours of rig time as the deep set plugs could not be retrieved in the conventional planned slick line operations.
This paper intends to highlight the challenges faced, and how PBP proved to be the optimum solution, by simplifying operations and ensuring the timely delivery of production.
The PBP operations proved viable through savings on energy, resources, time and cost associated with work-over jobs. The potential savings were roughly 780,000 bbls of oil which were significant for the aging asset. It is therefore, a potent alternative to other costly solutions in a scenario that often fails to deliver objectives, as happened in this campaign.
This paper presents the significant benefits accomplished from the utilization of robotic, electric-line (e-line) intervention to mill out a malfunctioning flapper valve versus the use of coiled tubing (CT). In addition, it will discuss the flexibility and control features of e-line based, intervention technology towards addressing short lead time and design modifications required to meet dynamic well challenges.
On the West Coast of India a well was completed using a flapper valve as the method of isolating the completion while being installing it into the well. A standard practice in the field, the flapper valve has been utilized successfully for a decade without any failures. Hence, during the current operation, contingencies to overcome a mechanical failure to open the valve were not on board. And unfortunately, in this particular well, the flapper valve failed to open as per SOP.
After multiple days spent on attempting to cycle open, attempts were then made with slickline to determine if debris accumulation was an issue. When this proved false, it was concluded that the flapper valve was mechanically stuck.
After evaluation of solutions incorporating CT and e-line interventions, it was determined that standard milling operations would pose additional challenges for the well due to the design of the completion below the flapper valve which incorporated a 2.56" restriction. If the milled portion of the flapper valve was not retrieved there was consequential risk that the well could become plugged by the coupon.
After an extensive review with the PMT JV (Panna, Mukta and Tapti Joint Venture) plus the Design and Engineering team of a service provider, it was agreed that the probability of retrieving the milled fIapper valve coupon with standard bits was low. However, the service provider suggested a unique, star shaped milling bit that enabled milling a coupon which was small enough to pass through the restriction should it not be captured. E-line milling was selected due to several reasons including the finer control, efficiency of operations and minimum debris generation.
The newly designed ‘star’ bit enabled milling a small coupon and subsequently expanding that hole to the desired OD of 2.7" which would enable access for future interventions as needed. The total time from the identification of the problem to designing, manufacturing, testing the new bit, transporting it to India and executing the solution was less than 45 days. This enabled the well to be intervened upon while the rig was on the platform. The operation itself was carried out within 45 hours vs the 120 hours projected for CT, leading to a cost saving of ~ 750,000 USD. This unique methodology also enabled early onset of production, avoiding a delay of ~ three months.
This was the first time this new mill bit was applied and the first time that this type of flapper valve had been milled out. Existing, standard bit designs were not sufficient to accomplish this solution nor were conventional approaches satisfactory in today's economic climate.
Agrawal, G. (Schlumberger Asia Services Ltd) | Verma, V. (Schlumberger Asia Services Ltd) | Gupta, S. (Schlumberger Asia Services Ltd) | Singh, R. (Schlumberger Asia Services Ltd) | Pandey, A. (Schlumberger Asia Services Ltd) | Kumar, A. (Schlumberger Asia Services Ltd) | Chadha, H. K. (Oil & Natural Gas Corp. Ltd) | Agarwal, A. K. (Oil & Natural Gas Corp. Ltd) | Chaudhary, S. (Oil & Natural Gas Corp. Ltd) | Saxena, R. (Oil & Natural Gas Corp. Ltd)
A field in western offshore India proved to be a major hydrocarbon-bearing structure, but wells in the field gradually declined in reservoir pressure and production when they were self-flowing. To improve recovery, water injection was performed, which almost doubled the field production. However, water cut eventually increased drastically, thereby reducing oil production. To curtail increasing water cut and improve oil recovery, a tertiary recovery method was sought.
After closely studying various recovery methods, simultaneous water and gas (SWAG) injection was proposed in which a predefined mixture of produced gas and water was injected to improve oil sweep and reduce residual oil saturation by oil swelling, ultimately increasing oil recovery. However, to practically observe field suitability and feasibility of the SWAG method, a pilot project that included four injectors and one producer was launched.
Efficiency of SWAG injection increases as a result of the consistent gas and water fine bubble flow regime developed in the wellbore, depending on casing size, tubing-shoe distance from perforation, and deviation. To evaluate this efficiency, production logging with optical probes to detect gas holdup was proposed in three injectors with different casing sizes and deviations. The existing wellbore flow regime from results of production logging were observed and compared with respect to favorable flow behavior to understand the effect of these factors on SWAG injection effectiveness. We found and suggested the deviation and casing-size configuration that was deemed optimal.
This was the first time production logging was used in India to evaluate the SWAG injection wellbore flow regime, and the method proved effective. The results are to be used for full-field SWAG injection implementation to improve overall field recovery.