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.
In present study, local manufactured food products such as bread, pastry, bakery biscuits and one company product parle-G Biscuit were selected for microbial count and characterized the isolated contaminant on the basis of biochemical tests. In Local bread contained 2.86 x104 bacterial cells per gm, bakery biscuits find average 2.96x103 bacterial cells per gm and in pastry, and average 2.73 x103 bacterial cells per gm were present. But parle-G Biscuit did not contain any microorganism. Further, isolated contaminant were characterized by biochemical tests and observed that isolated strains were Bacillus spp., E. coil and Klebsiella spp.
Coiled tubing (CT) sand plug operations associated with multistage fracturing operations in high-pressure/high-temperature (HP/HT) wells are very challenging, in part because of the small number of such jobs that have been performed worldwide. The wells in "A" field in India have HP/HT formations, with a bottomhole temperature (BHT) of 310°F and a reservoir pressure of 9,000 psi. Although millable bridge plugs are preferred industry-wide, this case illustrates how sand plugs become a suitable alternate solution for multistage stimulation to address space limitations, equipment and completion restrictions, and small tubing sizes, even in challenging downhole conditions. This study provides solutions to operational challenges of low injectivity and completion restrictions, which preclude bullheading and use of conventional bridge plugs. Simulations were sensitized to identify the best solutions for sand settling time, HP/HT conditions, pumping rates, CT speeds, and cleanouts where calcite or scale deposits on sand hinder bottomhole assembly (BHA) penetration. Best practices are given for sand plug operations in challenging HP/HT environments; those best practices can be applied as a reference to design, prepare, and safely perform CT sand plug jobs in such conditions around the world. To address operational challenges in the cases presented here, the first three stages were bullheaded and the last two (a total 325-m sand plug) were placed using CT. Wireline was run to verify CT sand plug tag at ×200-m measured depth (MD). After the successful refracturing job, the 340-m sand plug was cleaned out, followed by acid spotting and squeeze using CT to rejuvenate the lowest zone. Strict application of the recommendations prevented the occurrence of operational contingencies, such as stuck CT, sand bridging, and settling of sand in surface equipment.
Mesozoic age Golapalli sands are found in the Krishna Godavari Basin, located in the East coast of India. These sands are highly prospective for hydrocarbon exploration and development. They comprise of syn rift sediments, often, exhibiting low permeability. In general, these reservoirs do not flow naturally without hydraulic fracturing. Oil presence in Golapalli sands has already been proven in the basin from the exploratory wells. However, conventional saturation modeling using basic petrophysical logs has proved futile in establishing a definite oil water contact (OWC). This adds further complexity in the reserve evaluation and the hydraulic fracturing design. Moreover, the field is divided into multiple fault blocks with localized OWCs. During the initial appraisal phase, wells that were hydraulically fractured produced oil with high water cut. This prompted re-evaluation of saturation modelling with 3 further appraisal wells. All new wells were selected at different fault blocks within the field and were to be drilled as slim holes of 5-7/8in diameter in reservoir section. Potential intervals with natural fractures were successfully evaluated using advanced sonic data. Zones of interest were selected integrating the fractures network identified with advance sonic measurements and high porosity values obtained from basic neutron-density logs. To constrain inversion resistivity-based saturation modelling, a new workflow was adopted to determine reservoir fluid movements prior to hydraulic fracturing in less than 0.05mD formation. Through this approach, fluid saturations were successfully evaluated using a deterministic downhole fluid identification which helped in reducing saturation uncertainties while demarking the transition zone between oil and water in 0.05mD formation. With known oil zone identified, advanced sonic measurements were used to design effective hydraulic fracture models. A successful hydraulic fracture was initiated with excellent oil production with significantly reduced water cut compared to previous wells. In this paper, a novel workflow will be presented that will help in characterizing fluids in tight sands (permeability less than 0.05mD). This workflow integrates the basic openhole logs and formation testing with conventional resistivity-based saturation modeling to accurately pinpoint the OWC in the tight sands. This workflow has applicability in unconventionally tight reservoirs where there is uncertainty in fluid saturations or fluid contacts. Through this methodology, the propagation of hydraulic fracture into the water zone can be prevented which will greatly help in reducing the water cut in such conditions.
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