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Gondalia, Ravi Ramniklal (Schlumberger) | Kumar, Rajeev Ranjan (Schlumberger) | Zacharia, Joseph (Schlumberger) | Shetty, Varun (Schlumberger) | Bandyopadhyay, Atanu (Schlumberger) | Narayan, Shashank (Schlumberger) | Bordeori, Krishna (Schlumberger) | Singh, Mukund Murari (Schlumberger) | Shah, Arpit (Schlumberger) | Choudhary, Dinesh (Schlumberger) | Sharma, Lovely (Schlumberger) | Ray, Maria Fernandes (Schlumberger) | Sarkar, Samarpita (Schlumberger) | Moulali, Shaik (Oil and Natural Gas Corporation Limited) | Das, Santanu (Oil and Natural Gas Corporation Limited) | Rao, Dasari Papa (Oil and Natural Gas Corporation Limited)
The Triassic–Jurassic petroleum system reserves in Krishna Godavari Basin are found at 3500 to 4500 m depth with bottomhole static temperature (BHST) ranging from 270 to 340°F. Hydraulic fracturing is required to produce economically from these wells because the in-situ permeability of these sands is in the range of ~ 0.01 md. Hence, after perforations, minimal production is observed or the flash production from these wells dies out in a short time span.
Between 2010 and 2017, several appraisal wells were drilled and completed using hydraulic fracturing in the onshore Krishna Godavari Basin. However, the success rate of effective fracture placement and sustained production enhancement due to hydraulic fracturing was limited. This was attributed to insufficient understanding of rock mechanical properties and lack of a refined fluid fracturing system despite using a superior fluid system like carboxymethyl hydroxypropyl guar (CMHPG) with organometallic zirconate-based crosslinkers.
In 2018, nine wells were successfully hydraulically fractured, and sustained production from these wells was established using a simple borate-based crosslinked fluid system. A key change for the field was rather than designing and pumping fracturing fluid based on only BHST, one of the critical components that led to better proppant placement is the stable fracturing fluid that was fine tuned for the well based on factors like change of source water, tubular shear exposure time for designed fracturing treatment pumping rate, and hydrocarbon properties. This combination of rock mechanical properties and fracturing fluids used is captured as the efficiency of the fluid system, and this governed the usage of fluid loss additives, again a novel introduction for the field. Finally, the key to producing these sands was adequate cleanup and minimal guar residue to maximize the proppant pack conductivity. The paper also discusses the strategy to design fluids with minimal guar loading to reduce polymer retention and to achieve maximum fracture fluid recovery. This robust management of fracturing fluids along with understanding of rock mechanical properties can be seen in the post-fracturing production results.
A challenge in oil-reservoir studies is evaluating the ability of geomechanical, statistical, and geophysical methods to predict discrete geological features. This problem arises frequently with fracture corridors, which are discrete, tabular subvertical fracture clusters. Fracture corridors can be inferred from well data such as horizontal-borehole-image logs. Unfortunately, well data, and especially borehole image logs, are sparse, and predictive methods are needed to fill in the gap between wells. One way to evaluate such methods is to compare predicted and inferred fracture corridors statistically, using chi-squared and contingency tables.
In this article, we propose a modified contingency table to validate fracture-corridor-prediction techniques. We introduce two important modifications to capture special aspects of fracture corridors. The first modification is the incorporation of exclusion zones where no fracture corridors can exist, and the second modification is taking into consideration the fuzzy nature of fracture-corridor indicators from wells such as circulation losses. An indicator is fuzzy when it has more than one possible interpretation. The reliability of an indicator is the probability that it correctly suggests a fracture corridor. The indicators with reliability of unity are hard indicators, and “soft” and “fuzzy” indicators are those with reliability that is less than unity.
A structural grid is overlaid on the reservoir top in an oil field. Each cell of the grid is examined for the presence and reliability of inferred fracture corridors and exclusion zones and the confidence level of predicted fracture corridors. The results are summarized in a contingency table and are used to calculate chi-squared and conditional probability of having an actual fracture corridor given a predicted fracture corridor.
Three actual case studies are included to demonstrate how single or joint predictive methods can be statistically evaluated and how conditional probabilities are calculated using the modified contingency tables. The first example tests seismic faults as indicators of fracture corridors. The other examples test fracture corridors predicted by a simple geomechanical method.
Gondalia, Ravi Ramniklal (Schlumberger) | Kumar, Rajeev Ranjan (Schlumberger) | Nand, Ujjwal (Schlumberger) | Bandyopadhyay, Atanu (Schlumberger) | Narayan, Shashank (Schlumberger) | Bordeori, Krishna (Schlumberger) | Singh, Mukund Murari (Schlumberger) | Shah, Arpit (Schlumberger) | Das, Santanu (Oil and Natural Gas Corporation Limited) | Rao, Dasari Papa (Oil and Natural Gas Corporation Limited) | Shaik, Moulali (Oil and Natural Gas Corporation Limited)
The Mandapeta-Malleswaram field in India comprises Triassic-Jurassic age sands found at 4000m– 4500m depth, where reservoir pressure ranges 6,000 psi to 9,500psi with static temperature up to 340°F. This tectonically active basin with strike slip stress regime causes a heterogeneous distribution of in-situ stress which complicates the design and execution of effective hydraulic fracturing treatments. Previous attempts at fracturing from 2013 to 2017 were not successful and geomechanics inputs were different from actual values. This paper describes the lifecycle of a production enhancement project, from construction of a geomechanics-enabled mechanical earth model (MEM) to the successful design and execution of fracturing jobs on nine wells increasing proppant placement by 250% compared to previous hydraulic fracturing campaign and achieving 730% incremental gain in gas production compared to pre- fracturing production.
Challenges like fracture modeling in tectonically stressed formations, issues of proppant admittance, and complicated fracture plane growth in highly deviated wells (>65°) were overcome by Geomechanical modeling. The modeling incorporated advanced 3D anisotropy measurements, providing better estimation of Young's modulus, Poisson's ratio, and horizontal stresses, resulting in realistic estimation of closure and breakdown pressure. Fault effects were modeled and taken into consideration for perforation depth selection and estimation of pumping pressure with model update based on extensive Minifrac injections and analysis.
This study describes the results of injection tests (step rate, pump in-flowback, and calibration injection tests) carried out in the field addressing specific challenges in each well. Pre frac diagnostic injection and decline analysis was used to calibrate the MEM and tailor the design for every well. Proper job preparation for well completions and extensive stability testing involving a borate-based fluid system has reduced the screen out risk and enabled successful fracture placement. Effective pressure management on the job eliminated the problem with frequent screen outs and led to successful execution of all nine jobs while increasing the average job size from 30 t to ~150 t of proppant per stage.
From this project, a practical guide to address issues of multiple complexities occurring simultaneously in a reservoir, such as the presence of tectonic stress, fracture misalignment, fissure mitigation, and high tortuosity was developed for future application in tectonically complex fields.
Hydraulic fracturing is the proven stimulation technique to exploit hydrocarbon reserves trapped in tight gas Indian reservoirs especially in Mandapeta field of Southern India. Fracturing technique was customized to obtain designed fracture geometry which in turn resulted in very good post frac gas production rates. This paper deals in detail, the necessity of fracturing in Mandapeta field, meager production gains obtained in earlier fracturing treatments, challenges for fracturing, quality assurance and quality control of fracturing fluid, design and successful execution of fracturing technique.
Mandapeta field is located in Krishna Godavari Basin situated in Southern part of India. Customization of fracturing technique produced impressive gas production rates from Mandapeta field compared to earlier treatments. Poor geophysical properties of the reservoir, leak-off characteristics, completion constraints and high near wellbore frictions were some of the challenges observed during fracturing treatments. As the reservoir is having very low permeability, hybrid fracturing treatment with a pad comprising around 75 percent linear / slick gel followed by cross-linked slurry was designed and implemented successfully.
Gas production gains up to 37000m3/d in a single well was observed. 20/40 mesh high strength proppant was used in these treatments and maximum job size pumped was 151MT. Hybrid frac treatment was carried out in an exploratory location which resulted in impressive gas gain paving a way to further development of field. Pre-frac acid treatments improved the well bore connectivity to the reservoir thereby enabling the higher proppant concentrations to pump during the treatments. Chemical compositions addressed the surface tension and mobility concerns of the fracturing in gas reservoirs which resulted in faster cleanup and gas production. Recent successes of fracturing made a way forward to aggressive fracturing campaigns in this field.
Hydraulic fracturing treatments have to be customized to specific reservoir conditions so as to obtain success. Candidate selection, modeling designs using sensitivity analysis, suitable pre-frac treatments, lab studies for optimization of fracturing fluid, customized hybrid fracture treatments played vital role in successful execution of fracturing treatments in Mandapeta field of Southern India which can be applied to other tight gas reservoirs.