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.
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.
Agrawal, G. (Schlumberger Asia Services Ltd) | Kumar, A. (Schlumberger Asia Services Ltd) | Verma, V. (Schlumberger Asia Services Ltd) | Mishra, A. (Schlumberger Asia Services Ltd) | Deori, B. (Schlumberger Asia Services Ltd) | Kaushik, Y. D. (Oil & Natural Gas Corp. Ltd.) | Gyani, O. N. (Oil & Natural Gas Corp. Ltd.) | Baishya, R. C. (Oil & Natural Gas Corp. Ltd.) | Shankar, R. (Oil & Natural Gas Corp. Ltd.) | Singh, B. (Oil & Natural Gas Corp. Ltd.)
XYZ, a marginal carbonate field in Western Offshore India was undertaken for development recently. During its exploration phase, around two decade ago, thick oil layer was discovered with high sour gas content (around 14000 ppm). The reservoir was delineated in small oil pool, where six wells were completed for production, including one water injector for pressure maintenance to support oil recovery. Production behavior of most of the wells had a unique response of rapid decline in short period of time with similar drastic loss in THP without any change in water cut. Production response of all these wells led the suspicion of near well bore skin development as the primary reason behind sharp decline in production.
Acid treatment as a quick fix solution in carbonates was ruled out because of possible communication with bottom aquifer; coil tubing had multiple operational challenges in such a high H2S environment. Hence, to overcome the challenges and perform root cause analysis, it was planned to carry out the best possible set of data acquisition with rigless operations and plan ahead for productivity improvement and design future intervention as well.
Production Logging, being an ideal diagnostic tool, was chosen to study the production profile and understand the reservoir and well behavior. Post analysis, a relatively new concept of selective stimulation with post perforation controlled dynamic underbalance technique was considered to be the best fit solution to address the skin and production decline problem in the field.
The technique proved to be very beneficial and provided substantial increase in the wells production. The skin debris obtained in the process were analyzed to identify the cause of skin development and production plunge. Based on the results, further interventions were carried out in the well, which again proved to be very efficacious and increased the field production significantly.
The paper has a detailed discussion on the root cause analysis and arriving to the appropriate solution for this kind of wells. It emphasizes on the importance of production logging prior to operation for better and successful planning and execution of the well intervention jobs leading to production gain. It also highlights the operational challenges in such hostile high H2S environment and the importance of planning and preparation to ensure safety of one and all.
There is increased confidence in LWD data because of the availability of new technology. Acquiring the maximum amount of data during drilling is standard practice when drilling highly deviated or horizontal wells to counteract high rig operating costs. In some cases, LWD services are completely replacing wireline services. Until just a few years ago, the wireline formation tester was the most common service used for formation pressure testing. Today, because of well complexity, the use of wireline testers is limited. High risks of tool sticking, invasion effects and additional rig days are some of the important factors giving LWD formation pressure testers a leading edge over its wireline counterpart.
Baker Hughes' formation pressure testing-while-drilling tool, TesTrakTM, was deployed for ONGC, India in March 2014 as a part of the new LWD contract. The LWD formation testing tool was used in more than 50 wells, displaying exemplary performance with a sealing efficiency of more than 95%. Equipped with state-of-the art-technology, the LWD formation pressure testing tool saved a huge amount of rig time. The tool delivers real-time answers for wellbore connectivity, pressure depletion, reservoir compartmentalization, fluid identification and drainage. In addition to reservoir characterization, the tool also aided perforation decisions.
The Mumbai High field comprises of two blocks: Mumbai High North (MHN) and Mumbai High South (MHS). The blocks are divided by a shale barrier that is used to assist in independent exploitation of reserves at the north and south fields of Mumbai High. Various oil and gas reservoirs, namely, (from top to bottom), L-I, L-II, L-III, L-IV and L-V, basal clastics and fractured basement are present on the Mumbai High project field. L-II and LIII are primarily the limestone oil reservoirs of Miocene age, and are further classified into several layers. [S.K. Mitra et.al., ONGC, Increased Oil Recovery From Mumbai High Through ESP Campaign; Offshore Technology Conference and Kharak Singh et.al. Mumbai High Redevelopment – Geo-Scientific Challenges and Technological Opportunities; 5th Conference & Exposition on Petroleum Geophysics]
While testing in high-mobility formations, the tests were completed in a shorter time because of the controlled drawdown rate maintained by the tool. But, against tight, supercharged or low-mobility formations, it took more time to obtain stabilized pressure readings. Rugose hole conditions and dynamic mud losses, often observed in this field, made pressure testing even more challenging. To optimize testing in such formations, a detailed data set encompassing the testing parameters for the tool, formation type and other important observations was compiled after every job performed. With meticulous pre-job planning and real-time log analysis, test points were chosen in each zone to be tested. A detailed study of the data set aided in the selection of the test type and selection of parameters while testing in the same zone or zones with a similar log response. The lessons learnt from the previous formation pressure testing experience, coupled with efficient real- time monitoring from the base and good communication with the rig team and base team during the job, enabled testing time to be reduced significantly, thus saving rig time and simultaneously giving the data before the BHA is pulled out of hole.
This paper presents the lessons learnt from the LWD formation pressure testing experience in India, the results obtained from various jobs, the accuracy of the data, the readings across various layers in Mumbai Offshore Basin (Mumbai High North and South and Neelam- Heera) and suggests best practices developed for the selection of optimized test parameters to increase accuracy, reduce testing time and reduce rig time without compromising data quality.
The recent achievement in unconventional reservoirs has established the objective of reevaluating the oil-bearing tight carbonates as potential oil production reservoirs. Of these carbonates, the Turonian Abu Roash D (AR/D) tight limestone in the Abu Sennan field of the Western Desert, Egypt contains oil, but has extremely poor recovery. The challenge in this study is to define the effective parameters that control the various petrophysical attributes of this tight reservoir and their influence on reservoir recovery.
Integrated sedimentological analysis and poroperm characterization was performed based on various data sets, including conventional core analysis, mercury injection tests, and petrographic inspection. A core-calibrated image-perm software algorithm was processed to evaluate the heterogeneity of reservoir pore system and to provide a continuous and azimuthal output of high resolution porosity and permeability.
The AR/D limestone succession (approximately 82 m thick) consists almost entirely of offshore-outer ramp bioclastic wackestone-mudstone facies, with the exception of a reduced reservoir-forming interval (approximately 10 m thick), which consists of inner- to mid-ramp facies. The outer-ramp offshore facies have very poor reservoir quality, with total porosity of less than 9% and permeability values that never exceed 0.1 mD. The reservoir-forming interval begins with storm beds of whole fossil rudstone and bioclastic wackestone, and gradationally terminates upward with inner-ramp shoal beds (5 m thick) of benthic foraminiferal peloidal packstone. The shoal facies measure a noticeably enhanced porosity (15 to 27%) with a relative increase in permeability (up to 2.3 mD). However, a petrographic inspection with resistivity image analysis showed a clear paucity of visible mega- and meso-pores or significant natural open fractures. This means that the reservoir pore system is of the intercrystalline microporosity type, which is confirmed by scanning electron microscope (SEM) and the measured pore throat radii ranging between 1 and 0.005µ. The prevalence of microporosity in the best zone of AR/D reservoir is also evident by a unimodal porosity range distribution shown by an image-perm output. This homogeneous and volumetrically significant microporosity nature may provide a favorable recovery if a suitable fracturing design is applied.
This study highlights the effect of microporosity types on the permeability of tight limestone reservoir, and emphasizes the workflow and benefits of the image-perm technique in evaluating the poroperm system and heterogeneity in the porosity distribution in carbonate reservoirs.
Parashar, Sarvagy (Schlumberger) | Sikdar, Koushik (Schlumberger) | Roy, Dipanka Behari (Schlumberger) | Shrivastava, Chandramani (Schlumberger) | Kumbhar, Vasant Balkrishna (Oil & Natural Gas Corp. Ltd.) | Majithia, Pritpal Singh (Oil & Natural Gas Corp. Ltd.) | Baishya, Ram Chandra (Oil & Natural Gas Corp. Ltd.) | Avtar, Ram (Oil & Natural Gas Corp. Ltd.)
Tapti-Daman is one of the major hydrocarbon-producing clastic sub basins situated in the northeast region of the Mumbai High structure in Western offshore India. Tapti-Daman sub-basin hosts more than 6 Km of clastic dominated sediments ranging from late Paleocene to Recent, underlained by basement rocks.
Drilling failure has been reported in few wells in Tapti-Daman block in the past, which subsequently resulted in well collapse and abandoning the drilled section. The limitation of stress computation in the deviated and horizontal wells further introduced complexity in overcoming the wellbore stability issue. To address this, an innovative methodology was developed to assess the stress regime in this field. An accurate estimation of the stress parameters in the backdrop of geological information led to a more accurate and reliable geomechanical model.
Using a multiwell dataset from the C-Structure in the Tapti-Daman block, stress azimuth from vertical and deviated wells was determined with an advanced interpretation module. The module utilizes the borehole microresistivity image-derived azimuths of drilling failure signatures (i.e. breakouts, induced fractures, etc.) to decipher the shape of the stress tensor (Q-factor) and azimuth of minimum horizontal stress. The detailed analysis of the Q-factor and Sh leads to determining stress regime and anisotropy (as a function of well trajectory).
The analysis revealed that the present day in situ stress in the study area is compressional in nature, where S3 is vertical (sH>sh>sV) and the minimum horizontal stress azimuth is towards NE-SW. This critical information is represented in 2D stereographic stress plots considering the Sv/Sh or Smax/Smin ratios to ascertain the safe window for various wellbore stability parameters such as sanding, breakout, mudloss, tensional fractures, anisotropy and probability of fracture opening with respect to insitu stresses.
The inferences derived provide an edge in optimizing the well trajectories to avoid wellbore stability issues.