This paper describes the wide application of Production Simulator System in deep water gas field, its benefits and effectiveness. Deep water and subsea production system requires transportation of a mixture of gas/water through long subsea tiebacks from the producing well to existing production facilities
Production Simulator System is extensively utilised by Subsea operators for planning their day to day operations and predicting the systems response to current conditions and/or operator actions. The networked production software allows users to optimise and improve the system performance by monitoring wells and facilities.
The optimisation process goes beyond basic operations, but extends into predicting impact of wells/manifolds start-up/shut down, subsea interventions on system performance and its deliverability. The tool also provides study on the integrity of subsea pipelines and critical flow for mid water pipelines to prevent shutdown of manifolds. Simulation studies have presented results, which were precisely similar to the real time data.
While use of long subsea tie backs allows for better project economics, long flowlines causes additional backpressure on the well tending to reduce flow rates due to liquid hold up and/or backpressure increase thereby affecting ultimate recoveries. The succeeding sections in this paper will discuss how such tie-backs tend to under-utilise reservoir energy and presents alternatives for improving field life and enhance the system efficiency.
Efficient monitoring of subsea gas well behavior, subsea system integrity, analyzing subsea pipelines performance and predicting problems with the software optimisation tool has resulted in significantly decreased downtime and effectively assisted in taking decisions for maintaining well production.
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
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.
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.
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.
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.
Ogra, Konark (Schlumberger) | Chandra, Yogesh (Oil & Natural Gas Corp. Ltd.) | Pandey, Arun (Schlumberger) | Verma, Vibhor (Schlumberger) | Kumar, Ajit (Schlumberger Asia Services Limited) | Sinha, Ravi (Schlumberger Asia Services Limited)
Production logging traditionally has been used to describe the flow characteristic of a well. Over the years with the advancement of the technology, for the techno economic success, deviated and horizontal wells have been drilled. Application of highly deviated and horizontal wells for field development primary recovery is now a worldwide practice.
Diagnosing production problems in a near horizontal environment is a herculean task; complex flow regimes in highly deviated well aggravate complications. At the same time, with advancement in completion system design, it has become imperative to evaluate the effectiveness of the new completion design. Unfortunately traditional production logging techniques have not been successful in these conditions.
One of the key issues in diagnosing production problems is detecting and distinguishing hydrocarbons in high water cut wells with water phase flowing as continuous medium at the low side and dispersed hydrocarbon phase at the high side of wellbore. Technologies like the digital entry fluid imaging tool and gas holdup optical sensor tool have proven to provide accurate results. For horizontal and highly deviated wells where recirculation, crossflow, and phase segregation further complicate the flow behavior, complete imaging of the wellbore is needed to characterize the wells.
In brownfield scenario, the complications aggravate and may require real-time decision making and intensive data analysis. Some of the typical brownfield issues are scale buildup due to immense water injection for pressure support, which is required for efficient oil displacement, complex fluid flow regime, recirculation due to insufficient lift, and casing damage resulting in unwanted formation water entry.
The study provides the most prolific summary and guide for case studies, success stories and lessons learned from the Mumbai High field in the last decade; evolution of the production logging tool from the most standard unit to multipoint digital entry fluid imaging, gas holdup optical sensor tools to identify and distinguish between the three fluid phases. The paradigm shifts towards the key technologies like flow scan imager to evaluate the complex borehole fluid behavior, flow regimes identification is also presented in this paper. The results derived are indispensable for future well placement campaign
The D1D3 gas field in Krishna Godavari basin has deep water Subsea structures namely well, manifold, Subsea Distribution Assembly (SDA), Deep Water Pipeline end manifold (DWPLEM). These structures will be monitored and controlled by a Subsea Control Module (SCM) installed on each particular structure and the top side Subsea control system "iconSCU?? supplied by Aker Kvaerner Subsea, Aberdeen. All SCMs have redundant Subsea Electronic modules (SEMs) with Fiber Optic communications (FO) & back up combined power signal (CPS) links connected to the top side monitoring system. SCM is a critical part of each subsea structure and if required may need to be replaced as and when failures are evident. For changing the Manifold SCM the associated flowing well to the specific manifold requires to be shut-in because the power supply to the associated well SCM is through manifold SCM via Electrical Distribution Box and hence causing production loss. To avoid this production loss, an innovative approach has been developed. The highlight of this approach is SCM change-out without taking any shutdown of the flowing wells or interrupting the production by using redundancy of communication and power to the manifold and well SCM in real time. While design was such that shut in of all wells for each associated manifold would be required to replace a manifold SCM, the approach described in this paper will illustrate how use of redundant power paths are used to keep all production online, while changing the manifold SCM. This necessitates designing and subsea installation of electrical distribution box/EFLs on a Deep Water Manifold while maintaining production.
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.
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.