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Gupta, M K (Oil and Natural Gas Corporation Ltd.) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd.) | Singh, V K (Oil and Natural Gas Corporation Ltd.) | Pawar, A S (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.)
In one of the offshore complex of ONGC, Carryover of liquid have been observed leading to tripping of gas compressors resulting a loss of significant amount of production. It was established that separation capacity of existing separators even at present operating conditions were not sufficient to process present production. Further an increase of 60% of present gas production is envisaged as per long term production profile. Hence, handling the present and envisaged increased production in the existing separators was explored.
To handle the envisaged enhanced production rate and to avoid carryover issue in existing separators, options such as feed nozzles enhancement and installation of inlet device was explored. Changing feed nozzles is a tedious job, require hot job and longer shut down period and requires complete integrity test of separators as recommended by ASME SEC-VIII, pressure vessel guidelines followed by R-stamping. Therefore modifications in separator internal was suggested which will enhance the separation capacity and can accommodate in the present and envisaged increase of future production.
The analysis revealed that even though the diameter and length of the separators are adequate to handle the load, it was established that the inlet nozzle of the separators are not adequate. Hence, considering many factors such as minimum pressure drop, ensuring good gas distribution, suppression of re-entrainment, momentum reduction and erosion velocity ratio of less than one, modifications in separator internal was suggested which will enhance the separation capacity and can accommodate the present and future envisaged increase of production of more than 60%. It was established in the study that this options of installation of inlet device can be done with minimum modifications and require minimum shutdown period. This option has been recommended and is under field implementation. Hence this work will provide a significant help to oil and gas personal to accommodate higher than design feed quantities in existing separators with minimum modifications and minimum shutdown period.
Simplified analytical methods are used in 1D geomechanics workflows to predict the rock's behavior during drilling, completion and production operations. These methods are simplistic in their approach and enable us in getting a time-efficient solution, however it does lose out on accuracy. In addition, by simplifying equations, we limit our ability to predict behavior of the borehole wall only i.e. near wellbore solutions. Using 1D analytical methods, we are unable to predict full field behavior in response to drilling and production activities. For example, when developing a field wide drilling plan or preparing a field development plan for a complex subsurface setting, a simplified approach may not be accurate enough and on the contrary, can be quite misleading. A 3D numerical solution on the other hand, honours subsurface features of a field and simulates for their effect on stresses. It generates solutions which are more akin to reality.
In this paper, difference between a simplified semi-quantitative well-centric approach (1D) and a full field numerical solution (3D) has been presented and discussed. The subsurface setting considered in this paper is quite complex - high dipping beds with pinch outs and low angled faults in a thrust regime. Wellbore stability and fault stability models have been constructed using well-centric approach and using a full field-wide 3D numerical solution and compared to understand the differences.
In this study, it was clearly observed that field-based approach provided us with more accurate estimation of overburden stresses, variation of pore pressure across the field, changes in stress magnitudes and captured its rotation due to pinch-outs and formation dips. For example, due to variation in topography, the well-centric overburden estimates at the toe of deviated well at reservoir level is lower by 0.21gm/cc as compared to the 3D model. It is also observed that within the field itself stress regime changes from normal to strike slip laterally across the reservoir. In comparison to 1D model, considerable differences in stable mud weight window of upto 1.5ppg is observed in wells located close to faults. This is due to effect of fault on stress magnitude and azimuth. Stress state of 4 faults were assessed and all are estimated to be critically stressed with elevated risk of damaging three wells cutting through. However, a simple 1D assessment of stress state of faults at wells cutting through them, show them to be stable.
Moreover, the 3D geomechanical properties that are input into the numerical simulation also play an important role on the results. The algorithms and data used to populate the properties away from the well, need to be validated and calibrated with the well data, to predict reliable results. As the subsurface was quite complex, and well data was not sampled optimally, both horizontally and vertically, the selection and optimum usage of 3D trends also became crucial.
By comparing the differences between 1D and 3D solutions, importance of 3D numerical modelling over 1D models is highlighted.
In-situ gelled acids have been used for acid diversion in heterogeneous carbonate reservoirs for more than two decades. Most of the gelled systems are based on an anionic polymer that has a cleaning problem after the acid treatments that leads to formation damage. This work evaluates a new cationic-polymer acid system with the self-breaking ability for the application as an acid divergent in carbonate reservoirs.
Experimental studies have been conducted to examine the rheological properties of the polymer-based acid systems. The apparent viscosities of the live and the partially neutralized acids at pH from 0 to 5 were measured against the shear rate (0 to 1,000 s-1). The impact of salinity and temperature (80 to 250°F) on the rheological properties of the acid system was also studied. The viscoelastic properties of the gelled acid system were evaluated using an oscillatory rheometer. Dynamic sweep tests were used to determine the elastic (G’) and viscous modulus (G") of the system. Single coreflood experiments were conducted on Indiana limestone cores to study the nature of diversion caused by the polymer-acid system. The impact of permeability contrast on the process of diversion was investigated by conducting dual coreflood experiments on Indiana limestone cores which had a permeability contrast of 1.5-20. CT scans were conducted to study the propagation of wormhole post acid injection for both single and dual corefloods.
The live acid system displayed a non-Newtonian shear-thinning behavior with the viscosity declining with temperature. For 5 wt% HCl and 20 gpt polymer content at 10 s-1, the viscosity decreased from 230 to 40 cp with temperature increasing from 88 to 250°F. Acid spending tests demonstrated that the acid generated a gel with a significant improvement in viscosity to 260 cp (at 250°F and 10 s-1) after it reached a pH of 2. The highly viscous gel plugged the wormhole and forced the acid that followed to the next higher permeability zone. The viscosity of gel continued to increase until it broke down to 69 cp (at 250°F and 10 s-1) at a pH of 4.8, which provides a self-breaking system and better cleaning. Coreflood studies indicated that the wormhole and the diversion process is dependent on the temperature and the flow rate. There was no indication of any damage caused by the system. The injected acid volume to breakthrough (PVBT) decreased from 2.2 to 1.4 when the temperature increased from 150 to 250°F.
The strong elastic nature of the gel (G’= 3.976 Pa at 1 Hz) formed by the partially neutralized acid system proves its suitability as a candidate for use as a diverting agent. This novel acid-polymer system has significant promise for usage in acid diversion to improve stimulation of carbonate reservoirs.
Ali Khan, Farhan (Weatherford) | Antonio Sierra, Tomas (Weatherford) | Gabriel Imbrea, Robert (Weatherford) | Robin Edwards, Michael (Weatherford) | Al-Rushoud, Ali (Kuwait Oil Company) | Al-Abdulhadi, Fahad (Kuwait Oil Company) | Shehab, Abdulaziz (Kuwait Oil Company) | Al-Ajeel, Fatemah (Kuwait Oil Company)
Project deliverables included gravel foundation preparation, concrete foundation installation, equipment reception and installation of conventional beam pumping units at 660 production wells in a remote field in Kuwait with a deadline of six months from equipment arrival. Equipment shipments schedules were sequential and therefore an execution strategy was required to successfully meet the project deadline. This paper describes the field operations strategy devised and adopted to successfully meet the deadline. A temporary operations base was set up at the remote field for coordination, equipment reception, inspection, consolidation, pre-assembly and dispatches. Operations were divided into six parallel processes as follows: 1. Equipment logistics 2. Gravel foundation preparations 3. Concrete foundation installations 4. Unit Pre-assembly 5. Pre-assembled units dispatches 6. Final unit installations Daily output targets were set for each process prior to the commencement of operations.
Baker Hughes drilled one horizontal well for major Indian operating company in a, low resistivity contrast field, onshore India. The candidate field / basin is a proved petroliferous basin, located in the northeastern corner of India. The scope of work for this project involved integrating geological and open hole offset parameters to build a Geosteering model. Integrated data included a study of offset well data from the field, regional and local dip analysis from wellbore images, and a review of structural maps. Successful integration of these data helped to steer the well in the desired zone as per plan and make the best use of the data and to reduce uncertainties in Geosteering, drilling. Although high-quality 16-sector images commonly yield bedding dip, fracture and other geological information, this paper emphasizes how real-time reservoir navigation decisions was made using Geosteering modelling, real-time image processing, dip picking study etc.
Wang, Gang (China University of Petroleum-Beijing) | Fan, Honghai (China University of Petroleum-Beijing) | Zhang, Wei (CNPC Engineering Technology R&D Company Limited) | Yang, Yang (China University of Petroleum-Beijing) | Han, Zili (CNPC Bohai Drilling Engineering Company Ltd.) | Wu, Hongxuan (CNPC Chuanqing Drilling Engineering Company Ltd.) | Li, Wanjun (CNPC Engineering Technology R&D Company Limited) | Li, Jiaying (CNPC Engineering Technology R&D Company Limited) | Zhou, Tuo (CNPC Engineering Technology R&D Company Limited) | Zhou, Haiqiu (CNPC Engineering Technology R&D Company Limited) | Liu, Jitong (CNPC Engineering Technology R&D Company Limited)
M15 well contains complex intervals, where anticlinal structures developed from faults make long mudstone barriers full of cracks, which makes it hard to predict pore pressure. Loss is one of the most serious problems during drilling and cementing, while blow out accidents happen sometimes. Previous casing programs hardly adjust to all complex intervals and conventional LCMs (loss control materials) play few roles. As a result, designated targets used to be rarely reached.
It is proved that low pressure intervals shall be isolated firmly and complex intervals as well as reservoirs should be developed in independent intervals, thus casing programs have been modified. 188 lab tests were finalized, including 180°C hot rolling, anti-contamination test, lubricity test and inhibition experiments, in order to develop a kind of organic salt mud system that has premium inhibition, plugging, lubricating, heat & salt resistance properties. Precise MPD (managed pressure drilling) techniques are recommended to achieve near-balance drilling operation, solving borehole instability problems to some extent.
In the second interval the organic salt mud system is applied, while logging and casing running may be accomplished in one time. Besides, strings can be tripped out smoothly and high pressure brine productive zones are drilled safely. φ339.7mm casing joints are set at the depth of 3848m in the second interval and φ244.5mm casing joints are set at the depth of 5177m in the third interval, in order that deeper complex formation may be developed in a separate casing interval in which precise MPD is applied with LCMs while drilling and compound plugging agents. Therefore, downhole pressure is precisely controlled and large cracks are plugged statically on 28 occasions. Designated targets have been all reached and 20 oil & gas productive layers have been developed.
Downhole complexities arising from loss and blowout have been solved in M15, where φ339.7mm casing was set at the deepest interval in CNPC overseas operation history, making a new record of safe drilling operation, borehole quality and cementing quality. More oil and gas productive zones have been discovered and all designated targets have been achieved. New drilling experience got from M15 has significant meanings in the development of similar blocks.
Kisku, Sayanima (Oil & Natural Gas Corporation Ltd.) | Santhosh Kumar, R. (Oil & Natural Gas Corporation Ltd.) | Dayal, Har sharad (Oil & Natural Gas Corporation Ltd.) | Chadha, Harish Kumar (Oil & Natural Gas Corporation Ltd.) | Srivastava, Anil (Oil & Natural Gas Corporation Ltd.)
Infill drilling is an integral part of brown field management for exploiting un-drained areas with good oil saturation. In a matured field on water-flood, the primary objective is optimized wellbore placement of infill wells in areas with better petro-physical characteristics, bypassing flooded region. It is also important to design a robust completion strategy to safeguard the longevity of these wells by curtailing produced water. This approach assists in dramatic increase in production by isolating water charged sections and thereby restricting rise in water production.
The use of advanced Logging-While-Drilling techniques during horizontal drilling provides an opportunity for effective well planning. Real-time Logging-While-Drilling instruments during directional drilling gives us the opportunity to acquire information pertaining to the reservoir in a single run. Interpretation from the real-time data acquisition boosts the planning during wellbore drilling.
This paper discusses a case study of a field in western offshore, India, which focuses on the applications of geosteering and the use of swell packers for zonal isolation to augment oil production. In this study, two wells have been deliberated where the real-time information has been extracted and included in the decision making process. The bottom-hole assembly used in this case, comprised standard Logging-While-Drilling services such as gamma ray, resistivity, neutron porosity, density and density imaging services and also formation pressure testing.
Since the field under study is a carbonate reservoir that has been on waterflood for the last twenty eight years, chances of early breakthrough of water in the infill wells has posed a high risk in spite of the presence of good bypassed oil saturation. Geosteering has enabled to restrict the horizontal section safely within the desired zone of better oil saturation and geological features, as interpreted from the Logging-While-Drilling data. Further isolation of suspected water bearing zones with swell packers have assisted in healthy well completion by diminishing chances of sharp rise in water cut in the infill wells.
Panna Formation is a very critical and challenging formation deposited during Paleocene time of geological past in various parts of Western Offshore Basin of India. It was deposited in a fluvio-deltaic environment, sometimes even in a restricted marine set-up. Such variation in depositional setting caused mineralogical complexity, which in-turn imposed a limitation in conventional approach of formation evaluation and saturation determination to identify the pay zones with confidence. A comprehensive approach of integrated formation evaluation for rock quality characterization was attempted using a combination of new generation elemental and acoustic analysis for delineating the potential hydrocarbon bearing zones independent of conventional resistivity-based approach along with a better insight on formation heterogeneity. The studied well was drilled up to Panna Formation and conventional open-hole logs were acquired while drilling. However, due to complex mineralogical nature of the formation, estimation of key critical reservoir parameters was very challenging and imposed higher uncertainties in the results. An alternate approach was adopted using a few advanced log measurements to address this challenge. A combination of new generation elemental and acoustic data has been recorded in a single wireline run after acquiring conventional basic logs while drilling. An accurate porosity was derived by eliminating various mineralogical assemblages along with estimation of a geochemical permeability based on detailed elemental analysis. Measured aluminum from neutron inelastic capture spectrum method enabled to estimate clay volumes with accuracy, which provided the required insight for better effective porosity in such shaly-sand environment. Based on this improved porosity and permeability, an approach for rock-quality indexing was used for reservoir delineation.
Moreover, a good amount of organic carbon was found associated with clays caused shales with higher resistivity. Based on elemental measurements an interesting insight was possible to extract for resistivity independent fluid saturation. An additional pay zone with hydrocarbon saturation based on such resistivity independent approach was possible to identify, which was masked by conventional resistivity-based interpretation. Acoustic analysis results assisted in delineating the zones with possible open fractures to avoid any possibility for unwanted fluid breakthrough.
Based on this approach of alternate integrated petrophysical analysis perforation zones were selected including an additional zone, which was masked based on conventional analysis. The well was started producing around 1,05,000 m3 gas with around 200 barrels of oil per day. This study showcased an alternate and efficient characterization approach for any such mineralogically challenging clastic formations.
After years of development, qualification and engineering, subsea compression technology is now a proven solution to increase the recovery factor for offshore gas developments. The first subsea compression system was installed at the Aasgard field in the Norwegian Sea, which was started up successfully on the 17 th. of September 2015. This project represents an important milestone for the oil and gas industry, as apart from representing the successful developments of new subsea processing technologies, subsea compression also proves itself a viable alternative field development option to oil and gas operators. The experience from Aasgard enables tomorrow's subsea compression solutions. The basis is increased field recovery by subsea compression. In addition it opens for wells stream and deep water applications, as well as CO 2 EOR. This paper aims to share Aker Solutions' experience on Aasgard Subsea Compression project, from the design and the project execution phases up to the operational phase, highlighting the key learnings from more than 50 000 hours of successful subsea operation. In addition, the paper will also describe the ongoing development activities to optimize the compression system delivered for Aasgard, with particular focus on increased field recovery and unit size and weight optimization without requiring qualification activities of new technologies. This new generation of subsea compression system will extend the applicability of this technology to a much wider range of fields and offshore regions.
Digital core generated from micro CT images of rock sample cutting and results obtained from digital core analysis are presented in this work as a substitute of conventional core study for Petrophysical evaluation. Conventional core extraction during drilling, core preservation and analysis are expensive, time consuming processes and often unavailable for small size fields. Moreover, routine and special core analysis results are a critical input for petrophysical characterization. In this situation, digital core study appears to be a cost effective substitute to ensure and validate petrophysical evaluation results.
High resolution 3D micro CT imaging and analysis was done on rock samples cut during drilling or on sidewall core plugs cut by wireline logging tool. Segmented micro CT image slices when combined in 3D space in three orthogonal directions, can be termed as digital core. Solid rock matrix, clay filled and porous rock portions are distinctly separable using micro CT images and their volume fractions can be estimated. Detail textural analysis in terms of Grain and pore throat size distribution of the rock is possible from digital core which controls storage capacity and flow behavior. Two critical petrophysical input parameters for fluid saturation (Sw) estimation are cementation exponent (m) and saturation exponent (n). These parameters are commonly computed from special core analysis (SCAL) on conventional core plugs. But digital core study can provide the estimates of ‘m’ and ‘n’ which replace the need of SCAL.
Digital core study has been carried out in three different reservoirs in west and east coast of India and the results were analyzed. Porosity and permeability data obtained from digital core was first compared with log analysis results and then used to identify different petro physical rock types (PRT). Fluid saturation (Sw) was estimated from resistivity log by using ‘m’ and ‘n’ exponent obtained from digital core seems to be more realistic and corroborates with well test results. Porosity, permeability, water saturation and rock types (PRT) were helped to build geo-cellular model (GCM) for small and marginal reservoir.
Enhanced reservoir characterization by using digital core study result has helped in better understanding and decision making for small and marginal fields where limited well data is available. Finally this leads to the preparation of field development plan (FDP). Digital core technique is less expensive, having quick turnaround time than conventional coring which has translated into high value business impact for any development project.