Nautiyal, Dilip Kumar (Oil & Natural Gas Corp. Ltd.) | Jain, Pradeep Kumar (Oil & Natural Gas Corp. Ltd.) | Lohar, Babu Lal (Oil & Natural Gas Corp. Ltd.) | Marathe, Rajendra Vithal (Oil & Natural Gas Corp. Ltd.)
A giant multi-layered carbonate reservoir in offshore India is undergoing water-flooding since 1987. Historically there have been about 930 producer and 250 injection strings in the field with about half of them active today. In order to have quick flood surveillance, flow streamline snapshots and flood-front maps have been attempted using in-house developed analytical technique assuming homogeneous, incompressible, unit mobility ratio displacement process.
The eleven producing unit of the reservoir are clubbed as five major stacks for streamline generation. Injection and production volumes are divided among these five stacks on the basis of existing history matched simulation model. The volumes are then normalized to obtain the relative strengths of the producers and injectors Macro level reservoir anisotropy is inherently taken care by the normalization process of rates. Reservoir boundary for each stack is simulated by placing large number of image wells along each boundary. The velocity and potential distribution in the reservoir are obtained using the principle of superposition. The velocity equation tracks the path of the fluid particle generating the flow streamlines.
Flood-front positions are generated by repeating the above process. The field water cut vs. pore volume of water injected is compared against the actual water cut vs. pore volume of water injected as a history matching process. Individual well water-cut are then superposed on the flood-front positions in the corresponding stack.
Flood front positions are corroborated to a large extent with the superposed water-cut in individual wells. Deviations in the actual water-cut trend are also observed in few areas. Recommendations for redistribution of injected water among the identified stacks are presented on a holistic basis to achieve better sweep efficiency in the reservoir and field trials are awaited.
The attempt is to use this fast and simple analytical technique on a desktop computer for quick water-flood surveillance of a large field.
Medavarapu, Kishorekumar (Oil & Natural Gas Corp. Ltd.) | Mahato, P.K. (Oil and Natural Gas Corporation Ltd) | Das, Santanu (Oil & Natural Gas Corp. Ltd.) | Singh, Sureshkumar (Oil & Natural Gas Corp. Ltd.) | Patel, Kantilal C. (Oil & Natural Gas Corp. Ltd.) | Nandan, Alok (Oil & Natural Gas Corp. Ltd.)
Customized hydraulic fracturing operations in low temperature and shallow reservoirs of Gamij field of western onshore India yielded impressive post frac production gains. This paper describes in detail, the various challenges for hydraulic fracturing in Gamij field, development of fracturing fluid, execution methodology and fracturing's vital role in production enhancement.
Successful hydraulic fracturing operations turned Gamij as one of the promising producing field. Poor reservoir characteristics, thin pay zones, presence of coal layers, shallow depths and low reservoir temperatures were the main challenges for hydraulic fracturing. Numerous lab studies carried out and fracturing fluids were customized for good rheological capabilities and post-frac gel cleanups. Frac job sizes were optimized based on sensitivity analysis carried out using frac simulators. Large size jobs were carried out in suitable candidate wells. Pre and Post frac temperature logs were taken to ascertain the fluid intake and frac confinements. Activation methodologies developed so as to bring the wells on production in minimum time.
Hydraulic fracturing jobs in Gamij field were quite successful. Fracturing jobs were carried out in 35 wells in the last two years mostly with drilling rig in position. Most of the wells came on self. Oil production up to 30m3/d in a single well was observed. Job sizes were designed based on reservoir characteristics which ranged from 60000 lb to 242500 lb. 20/40 low strength proppant pumped in these frac jobs with maximum concentration of 15 ppg. Job scheduling varied based on thickness of payzones, behavior of nearby coal layers. Temperature logs showed a good placement of proppant in target zones which helped in getting impressive post frac productions. The results of frac jobs turned this small field into one of the most promising fields in the area.
Customized hydraulic fracturing helped in the enhancing the production from ageing & mature western onshore oil fields of India. Success of fracturing campaign in Gamij field led to augmented drilling activity in similar pay zones to extract hydrocarbons and support the increasing energy demand. This strategic hydraulic fracturing methodology customized for other fields in the region which were also proved quite successful.
Bhushan, Yatindra (Cairn Energy Plc UK) | Singh, Amit Pal (Cairn India Ltd.) | Suresh Kumar, M. (Cairn Energy India Pty. Ltd.) | Shankar, Pranay (Cairn Energy India Pty. Ltd.) | Jha, Manish Kumar (Cairn India Ltd.)
The Mangala Field is located in the northern Barmer Basin of Rajasthan state, India. The basin is a Tertiary rift, predominantly consisting of Palaeocene-Eocene sediments. The Mangala Field was discovered in January 2004 and brought on production with hot water flooding in August 2009. The main reservoir units in the Mangala Field are the fluvial sandstones of the Fatehgarh Formation. The Fatehgarh Formation in the Mangala Field is subdivided into 5 reservoir layers termed FM1 (top) to FM5 (base). The lower part of the Fatehgarh Formation (FM3 to FM5) are dominated by well-connected sheet flood and braided channel sands, whilst the Upper Fatehgarh Formation (FM1 and FM2) is dominated by more sinuous, laterally migrating fluvial channel sands. The FM-1 unit hosts approximately half of the oil in place.
A detailed fine layer geological model was built for the Mangala Field incorporating all relevant data from the field generated over the last couple of years. A set of 100 realizations of the geological model were generated. All of the realizations for FM-1 layer were simulated in a commercial streamline simulator using the available historical production data for FM-1 wells.
The paper discusses the results from these multiple realization runs and the inputs given to the geological model which was used to improve the model further. These runs helped in identifying the areas where sand connectivity was low due to presence of some baffles or channel boundaries and needed improvement, to match fluid flow in the reservoir. After incorporating the PLT data into the dynamic model, the well wise water cut resembled the actual w/c and improved the confidence level on the geological model.
The paper also discusses well allocation factor estimates for each producer and injector pair from the streamline simulation model for different injection patterns in FM-1. The well allocation factors helped in understanding the level of support each producer is getting from the nearby injectors
The C- Series marginal gas field in Tapti is located approx. 60 KM West of Daman. Under Phase-I implementation, four unmanned well platforms namely C-22P, C-24P, C-39-P1 & C-39-PA have been installed. C-39-PA is the farthest platform and connected to C-24P via 60 kms of 22?? and C-24P to NQG process platform via 115 kms of 28?? sub-sea pipelines. Gas from NQG is transported to Uran after processing.
Pipeline is very long sub-sea pipeline bearing a very typical profile with un-favorable contour having multiple sources, having a reverse profile with C-series platforms at a shallow depth of 19-23m and the receiving process platform NQG at a depth of about 64 m. The gas, condensate and liquid production profile makes this pipeline more critical during regular production and having severe surging problems.
Dewatering and commissioning of the pipeline with a conventional approach to launch the pig train from the launcher at C-24 well platform and receiving the pig train at NQG receiver was considered initially. The pipeline filled with 60 thousand cubic meters of treated water. If pigging is done conventionally huge surges are anticipated at NQG, may cause process upset and may lead to shutdown of the process complex. Because of this a different way of launching the pig from receiver end i.e., (NQG), deeper pipeline profile and receiving the pig at C-24 platform, a shallower pipeline to ensure safe and practicable operation. The pigging was done successfully with nitrogen in between the 4 pig train followed by gas. After pigging of NQO-C-24 section, gas from C-24 platform was used to propel the pigs in 22?? pipeline segment. Finally, dewatering of both segments was carried out successfully and this is first time in ONGC, the operations carried out in a large scale
The health and effectiveness of any Integrated Control System depends on many factors. Among these factors is the proper design, selection of Control System, seamless integration, System Architecture, System Configuration, System Integration Testing, Control System Installation, Commissioning, Site Acceptance Test, Preventive Maintenance, Predictive Maintenance, Functional Testing etc.
The integrated solution for the Onshore, Offshore & Subsea Control System includes a dedicated Subsea Control System, DCS System, ESD System, Process Simulator System, F& G System, Large Screen Abnormal Situation Management Video Wall, Measurement Systems etc.
The power to the Offshore and communication to Offshore & Subsea is through Umbilical's. The backup communication from Onshore to Offshore is through dedicated Microwave Network. The communication from Onshore Terminal (OT) Control Room to Subsea wells is about 50 Km to 60 Km. The remote Subsea wells are Controlled and can be Shut down from OT.
The best-in-class technologies in Control & Safety was effectively implemented by deploying various protocols like Foundation Fieldbus, HART, Control Net, OPC, MODBUS TCP I/P, Serial Interface etc. The digital Control System reliably monitors and controls the over 1, 10,000 tags. All the DCS hardware is integrated with the non DCS hardware while having a common control system information. The System has the facility to provide information across the organization giving the best possible foundation for collaboration between people, processes and systems.
In such a large network of integration of technologies & integrated operations of Subsea & Onshore, identifying and minimizing control system errors are a big challenge. It is a big challenge to ensure continued operations of these facilities without any Trips.
This article focuses on Control & Instrumentation Systems contributing factors for uninterrupted Operations of Onshore/Offshore/Subsea facilities during the first 1033 days of operations & the challenges to ensure continued operations without any facility Trips.
Al Jubran, Hasan Hussain (Saudi Aramco) | Leal, Jairo (Saudi Aramco) | Al BuHassan, Shaker (Saudi Aramco) | Bolarinwa, Simeon (Saudi Aramco) | Pulson, Dave (Schlumberger) | Barnawi, Mazen (Schlumberger)
Saudi Aramco has recently initiated a change in gas well design in the Ghawar field of Saudi Arabia. The new approach is to drill deviated cased hole gas wells through the reservoir to increase the length of contact of the productive zone and thereby increase production potential. Typical gas wells were drilled as a vertical cased hole through the reservoir or open hole horizontal gas wells.
The increased well deviations, measured depths and resultant increase in reservoir sections required a new approach to the perforating solution for these wells to connect them to the gas plants. Various techniques were reviewed, considering safety, operating efficiency and well performance. The final solution was to deploy the perforating systems on electric coiled tubing (CT) and run all the guns in one run using completion insertion and retrieval under pressure (CIRP) as a deployment system, which allowed the guns to be run and pulled under live well conditions without having to kill the well.
This paper details the learning curve and lessons learned from the implementation of this technique in five gas wells. The deployment system and pressure control equipment were optimized to satisfy Saudi Aramco's requirement for three barriers. A CT cleanout run was added before perforation to remove any debris from the wellbore causing a problem to the depth correlation tools. An existing CT tower was used to support the very long wellhead stack, but due to its height limitation a special solution was implemented to enable safe CT operations. A deployment system under live well conditions was used to minimize CT runs, operating time and cost savings. The static underbalance condition was set before running the guns, combined with the dynamic underbalance perforating technique and deep penetrating charge gun design were implemented to optimize the well performance. This technique allowed safe and efficient perforating in a single underbalance run of these five gas wells.
The paper also covers the planning of the perforating solution, health, safety and environment (HSE) considerations, equipment selection, operational procedures, job execution and results.
CBM is likely to address in a limited way the world's growing energy needs. In India the epicenter of such a process is geographically active in the east, predominantly known for conventional coal mining. Devoid of any known natural gas resource, the area though conducive for CBM production, commercial prediction needs utmost care and caution, as supply commitment is never equipped with fall back option. The geological model thus for Barakar Formation of Bokaro Field is defined with reasonable confidence for three potential CBM seams assessed through 3 vertical wells with a deliverability 10,000 m3/d for the first tested well. Proven CBM potential volumes estimated thus needs to be translated into a way forward programme of monetization firmed up through simulation based profile.
A comprehensive full field dual porosity/permeability simulation model, incorporating Langmuir isotherm and GC data generated across the geographical spread is built to understand the process intricacy. Effort to history match the initial Qw with time in all CBM simulation as a depressurization event is a difficult proposition as interruption in Qw, coupled with Wp bookkeeping are often very subjective. However, permeability/volume modifiers within acceptable limits led to replicating near history of Qg and Gp. The prediction was QC'd on single well forecasting basis through other commercial software, and the profiles though identical was in substantial variation in gas breakthrough timing, the possible reasons identified as a learning for the future.
Field scale development with an optimized variant of 38 vertical wells at 60 acres well spacing envisages peak Qg of 1.3 LCMD and RF being 32% after 15 years. The criticality is however well scheduling designed to cater to the industry needs of a reasonable plateau period.
This paper assimilates the lessons learnt from the applications of simulation to be used for devising field scale CBM development strategy and is suggestive of the Do's and Don'ts of initial data generation and lists caution in the prediction specially the depressurization process, well spacing criteria, drilling schedule for plateau generation.
Kumar, Rajeev Ranjan (Schlumberger Asia Services Ltd) | Rao, Dhiresh Govind (Schlumberger) | Parashar, Sarvagya (Schlumberger) | Swain, Saraswat (Schlumberger) | Sikdar, Koushik (Schlumberger) | Majithia, Pritpal Singh (Oil & Natural Gas Corp. Ltd.) | G.V., Suresh (ONGC)
Tapti-Daman is one of the established prolific gas producing clastic sub-basin in offshore Mumbai, India. Paleo-Miocene shallow sands are the dominant reservoir in this area. Drilling surprises have been observed frequently in this area due to geomechanics-related wellbore instability. We present a case study showcasing detailed analysis and integration of multi-well advanced acoustic and borehole image data set. Considering the uncertainty with the variation in stress regime on well basis as compared to regional geological setting, it becomes critical to identify stress regime in order to optimize mud weight programme to drill high inclined wells where safe mud weight window becomes narrow. The borehole image analysis leads to identification of breakouts and drilling induced fractures which reveal horizontal stress directions whilst sonic anisotropy analysis provides more robust insight on maximum horizontal stress direction based on fast shear azimuth. In addition, radial profiles of fast shear and slow shear were used to invert and determine absolute values of maximum and minimum horizontal stress magnitudes. Integration of the high resolution data set reveals the present day stress regime of the study area is strike slip (sH>sV>sh) regime. Using the quantitative values of horizontal stresses determined at different depth intervals, a post-drill Mechanical Earth Model (MEM) was developed to perform history matching of predicted failure with observed drilling events. This model was then validated with another well in the field which clearly demonstrated the value addition of the sonic answer products and image analysis. Similar workflow can be adopted to address sanding propensity to optimize completion design to mitigate or manage sand production.
Knowledge of pore fluid pressure is essential for safe drilling and efficient reservoir modelling. An accurate estimation of pore pressure allows for more efficient selection of casing points and a reliable mud weight design. Current commonly used methods of pore pressure prediction are based on the difference between a ‘normal trend' in sonic wave velocity, formation resistivity factor (FRF), or d-exponent (a function of drilling parameters) and the observed value of these parameters in over-pressured zones. The majority of the techniques are based on shale behaviour, which typically exhibits a strong relationship between porosity and pore fluid pressure. However, carbonate rocks are stiffer and may contain over-pressures without any associated influence on porosity. Indeed, the application of common pore pressure prediction methods to carbonate rocks can yield large and potentially dangerous errors, even suggesting absences or decrease in abnormal pressure in zones of high magnitude over-pressure. In some cases, the hypothesises which been in the conventional methods seems to be flawed in some cases where pore pressure decreases by depth.
In this research, a new method for effective stress calculation has been obtained using the compressibility attribute of reservoir rocks. In the case of over-pressure generation by undercompaction (as occurs in most clastic over-pressured sequences), pore pressure is dependent on the changes in pore space, which is a function of rock and pore compressibility. In simple terms, pore space decreases while the formation under goes compaction, and this imposes pressure on the fluid which fills the pores. A carbonate reservoir in a field in Iran has been investigated to establish pore fluid pressure generation mechanisms, and to attempt new methods for pore pressure prediction in carbonate rocks.
The presence of paraffin in crude oil often leads to wax deposition in pipelines when temperatures reach below Wax appearance temperatures. It is possible to simulate the wax build up using thermodynamic and kinetic/deposition models for estimating wax deposition with varied degree of accuracy. The most popular remediation technique for wax removal is direct mechanical cleaning using pigs as these are generally cheaper than chemical inhibitors. The pigging frequency is mostly determined using thumb rules and operating experience. Correct pigging frequency is essential to avoid significant wax build-up in pipeline that may lead to plugging or stuck pig. This becomes more acute in subsea lines where insufficient well head pressures driving the pig may not scrap out the wax plug ahead of pig. This can increase to downtime and can lead to expensive pipeline repair.
In Mumbai offshore pigging is most common method of wax removal in well fluid lines. In this paper a simulation model using dynamic simulator for predicting daily wax build-up and pigging shall be discussed. The model is based on the actual pipeline condition, fluid parameters and pigging data. Extensive lab studies on actual comingled well fluid samples from platform have been carried out for capturing the Fluid & Wax properties.
The model has been used to run what if scenarios by varying the pigging frequency for the pipelines. The impact of ambient temperature or increase in gas (lift gas) in well fluid on pigging has been studied. Sensitivity studies have been carried out for various parameters like wax plug friction, bypass opening, change in well fluid parameters, etc.