Amongst all issues plaguing drilling operations, wellbore instability and failure is still a leading contributor to drilling non-productive time (NPT). Failure can result from misunderstanding the wellbore conditions, improper drilling practices, unavailability of geomechanical properties or improper interpretation of those values. For maximum long-term production, it is desirable to avoid uncertainties associated with wellbore integrity during drilling. Wellbore integrity deals with identifying the optimal drilling fluid properties and formulations to avoid unwanted surprises while drilling. It is well-documented that near-wellbore stresses can be altered by adopting different approaches to maintain or increase wellbore integrity while staying within the drilling window (pore pressure and fracture gradient).
The results from testing methods for curing wellbore instability using drilling fluids containing products like gilsonite/asphaltene were input into a numerical simulator to understand their stabilizing effect on wellbore. Increase in the near-wellbore stresses was observed for certain drilling fluids; however, a destabilizing effect was observed for a few fluids. The wellbore strengthening technique includes inducing fractures in problematic zones like depleted formations and inter-bedded sand layers. The fractures are then propped open with lost circulation materials (LCM) to sustain the increase in the near-wellbore effective tangential stresses. Different combinations of LCM were tested to indentify the optimal combination. Enhanced performance was observed after the addition of high aspect ratio material in LCM pill.
This paper presents comprehensive information on the different mechanisms employed to improve wellbore integrity. Application of different laboratory methods and materials in combination with numerical simulator analysis are provided to demonstrate different approaches for wellbore integrity management in various scenarios.
Liu, Guang Hua (PetroChinaDagang Oilfield Company) | Cui, Hui Kai (PetroChinaDagang Oilfield Company) | Fould, Jeremie Cyril (Schlumberger) | Lee, J.S. (Schlumberger) | Wang, Hailong (Schlumberger) | Zhang, Xingguo (Schlumberger) | Aviles, Isaac (Schlumberger) | Baihly, Jason David (Schlumberger)
Drilling activity has been steadily ramping up in China to meet the countries energy demand and government production goals. This is moving some activity to previously unexploited ‘tight' formations requiring hydraulic fracturing to produce economically. These formations have historically been producing with stimulated vertical wells and some horizontal un-stimulated wells. Many of these tight reservoirs exist in the Bohai Basin of Eastern China.
In order to quickly ramp up production to meet the governments' goals, new drilling and completion techniques are being used including completing horizontal wells with multistage hydraulic fractures in some fields. In some low producing areas new methods of isolating and stimulating wells are being investigated by the operator. New stimulation isolation methods must be streamlined as much as possible in order to achieve the production goals quickly and economically.
One of the new completion systems that was developed for cemented wells requiring multistage stimulation us generically called the treat and produce (TAP) completion system. This high efficiency completion system has recently been used in China's Dagang field to stimulate a horizontal well.
The TAP system was run by the operator in the Dagang field, where cased and cemented vertical completions are common and require artificial lift to produce. Horizontal cemented completions have been recently introduced as a means to increase field wide production. Although plug and perforating methods are
applicable for these wells, the client turned to a more efficient solution. TAP systems permit continuous pumping operations to be performed while precisely placing multiple hydraulic fracture treatments along the horizontal section; immediate flowback is possible for further production and efficiency gains.
In order to efficiently complete the horizontal well, a treat and produce (TAP) system was used in order to complete the well. This completion system uses a series of sliding sleeve valves that are installed as part of the casing string. These valves are actuated by pressure and sliding sleeves with graduated ball seats.
This paper describes the TAP completion system and its application in the Dangang field in China. TAP completions enabled optimized fractures placement and propagation in cemented completions that resulted in efficiency and production gains for the client, proving the application for the field. By means of a case history, the specific design and operation of the TAP completions system are discussed.
An offshore operator in Malaysia detected an unexplained annulus pressure increase after completing a large-bore gas production well. A leak detection tool was run on an electric line tractor and located leaking tubing connections at 333 m and 394 m MD. This led the operator to recomplete the well.
The operator chose to close a fluid loss isolation valve at 1800 m MD. Because an electric line tractor, hydraulic stroking tool, and key tool were already onboard the platform as a contingency to open the valve, this suit of technology was chosen to close the valve.
The toolstring was configured with a 4.625?? key pad to fit into the sliding sleeve of the valve and run in the hole. The tractor was activated 146 m above the valve and then driven down to the valve where a depth correlation was made. Then the toolstring was placed with the key extended until it reached the recess area above the shifting profile. The piston of the hydraulic stroker was extended with the key pads expanded and located the shifting profile. Next, the hydraulic stroker was activated to stroke up and thereby closed the ball valve.
The valve was closed in 15 hours from rig up to rig down, including 2 hours of inflow test. This was the first time such a valve has been closed on electric line in Asia Pacific and the operation proved the viability and efficiency of the technology. Importantly, the operator did not kill the well and saved significant costs by cutting the time in half compared to a workover.
This paper will present the learning from the operation while discussing this newly adopted approach and the benefits it offers to the industry.
During acidization of multilayered wells, major portion of the acids preferably enter into high permeable layers bypassing the low permeable layers. To combat the challenge a self-diverting acid (SDA) was developed with conventional chemicals for effective stimulation of all the layers. The technique involves a stable retarded acid system, a plain acid, a viscous diversion system and a chemical formulation for taking care of wettability issue of the formation rock. Descaling and formation preconditioning were also included for effective treatment and flow back. Two polymers were evaluated in the laboratory for customization of diversion system. The concentration of polymer was optimized to achieve the optimum viscosity required to divert the acid based on the reservoir properties and the flow back after the treatment.
The technique has been implemented in 31 multilayered wells of Mumbai High, a major offshore oil field in India, consists of multilayered carbonate reservoirs, with substantial heterogeneities among the layers. All the candidates were selected with MDT approach. Well specific treatment designs were carried out considering the damage mechanism, reservoir properties and well completions. The treatments were designed in multiple stages of preflush, acids, diversion systems and postflush. The chemical formulation for wettability alteration was used in selected wells.
The placement was carried out by bull-heading and real time treatment plots were recorded in each job. The treatment plots indicate effective acid exposure and uniform stimulation among the layers. Post treatment analysis indicated significant oil gain. This paper will cover the critical areas of stimulation in multilayered wells, details of the SDA technique, treatment methodology, design and post treatment evaluation.
Key words: SDA, Stimulation, MH
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 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
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.
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.
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