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Drilling Operations
Abstract The continuous improvements in high-speed communications and information technology are transforming traditional drilling working practices. For some services such as data and LWD engineering, personnel no longer need to be physically present at the rig site. New technology guarantees their virtual presence. Instead, these positions can be moved onshore, adding to the overall team capability and efficiency. At the same time, this reduces the over all HSE exposure and offers further potential savings in bedspace and transportation costs. To effect this transition, each of people, process and technology challenges have had to be addressed. These concepts have been embodied in the "Baker Expert Advisory Center/Operations Network" (BEACON) system, established in Stavanger, Norway. The paper describes the challenges faced in establishing the system and their solutions. Human factors are shown to play a crucial role in its successful implementation, demanding greater flexibility in onshore working practices to match those remaining offshore and to establish the virtual team. During the initial trial period, these factors, compounded by reliability and maintenance problems caused the system's operation to be suspended. Following a review, operations were restarted and two wells have now been successfully drilled in this operational mode. Improvement in the team's decision-making capability is evident and has been described as "increasing the team IQ". Improved access to the onshore centre, compared with offshore, is now shown to increase reliability and flexibility. Finally, the paper summarises the future work planned under the Norwegian Demo2000 sponsorship program, which will address the provision of these services in more formal terms. Introduction In the late 1990's, Baker Hughes INTEQ realised that a great deal of effort had been expended, developing new and improved technologies that led to significant improvements in well delivery times. However, non-productive time remains high and further improvements in operational efficiency are still necessary. Less effort has been devoted to developing the organization, identifying better and smarter work methods. Information communications technology was seen to offer the greatest potential to improve work efficiency and to use our most important resource, the human capital, in new and improved ways. At the same time, many oil companies operating in the North Sea had invested a lot in a fibre optic cable infrastructure on the seabed. To a large extent, the scale of the investment was based on conviction and historical technological progress rather than on a clearly defined plan of how the new capacity would be used. Operationally, bed space offshore was at a premium and innovative solutions were being sought to relieve the pressure on this valuable commodity. The HSE benefits of moving personnel onshore were also recognised. Historical Background The idea of enhancing rig site support from the office is not a new one. Advances in electronic communications and personal computer technology prompted the first wave of drilling operations centers in the early 1980's. Included in this first wave were Mobil's Drilling Data Centre which evolved from Superior Oil's real time drilling data centre and Amoco's Drilling Command and Control system. These centers distinguished themselves by providing real time log and MWD data to the shore based teams. Most other systems developed at that time were less ambitous, and their functionality was focused on the creation of a drilling database and electronic input and transmission of the morning drilling report. Of these two systems, only the Mobil Drilling Data Centre is still in operation. The Amoco Critical Drilling Facility was shut down in 1989. The circumstances that led to its shutdown provide valuable learnings that will be discussed later in this paper.
- North America > United States (1.00)
- Europe > Norway > North Sea (0.48)
- Europe > United Kingdom > North Sea (0.34)
- Europe > Norway > Rogaland > Stavanger (0.25)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.47)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/16a > Eastern Trough Area Project > Mungo Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/20 > Eastern Trough Area Project > Mungo Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- (15 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation (1.00)
- Well Drilling > Drilling Equipment (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)
- Information Technology > Information Management (1.00)
- Information Technology > Communications > Collaboration (1.00)
- Information Technology > Architecture > Real Time Systems (0.87)
Abstract The giant Statoil-operated North Sea oil field Statfjord is currently far down its production decline curve. During 23 years of production more than 60% of the STOOIP has been recovered, and the remaining reserves are characterized by complex distributions of oil, water and gas. In order to obtain a cost-effective production of the remaining oil, an aggressive drilling and intervention programme is necessary. The main challenge that the geoscientists and reservoir engineers face in this scenario is to identify remaining oil in targets becoming increasingly smaller, more complex and more uncertain, and to drain these in the most profitable manner. This paper reviews the working method that has been used at the Statfjord Field when defining a drilling schedule. It shows how the different work processes are linked, starting with the identification of possible new well locations, continuing with the estimation of reserves and risk evaluation and ending up with final drilling projects. Introduction The Statfjord Field was discovered in 1973, declared commercial in August 1974, and started production in 1979. The field is more than 25 km long and averages 4 km in width, and is the largest producing oil field in Europe. Statfjord is located in the Tampen Spur area, in the northern portion of the Viking Graben and straddles the border between the Norwegian and UK sectors. Figure 1 shows a map of the Tampen area. The field is developed by three fully integrated Condeep concrete platforms, from north to south, the Statfjord C, A and B platforms. All three platforms have tie-ins, as shown in Figure 2. Production is from the Brent, Dunlin and Statfjord reservoirs, with Brent and Statfjord being the main reservoirs. Cumulative oil production as of May 2002 is 612 million Sm, giving a current recovery of 60% of the STOOIP. The expected recovery factor is 65%. The oil production along with injection of water and gas has resulted in a field with three phases and several fluid contacts. The remaining reserves are therefore scattered over a wide area and in several reservoirs. Consequently each new well location is gradually decreasing in size and associated with considerable risk. Presently, each location is still economic but requires a considerable effort to mature. A multidisciplinary organization applying well-defined work processes is necessary to recover the remaining reserves in a cost-effective manner. Resulting in an optimised drilling programme, the implementation of the work processes ensures the maintenance of a high activity level in the field. Field Status Production History. Since its discovery in 1973, more than 280 wells have been drilled on the Statfjord Field. About 340 production logs and 220 saturation logs have been acquired. At present the activity level on Statfjord is higher than ever, with a drilling schedule comprising 15 infill wells drilled per year and more than 100 annual well interventions. There are currently 124 active wells in the field, and no spare slots available. Therefore all new wells are drilled as sidetracks from existing wells. Figure 3 illustrates the significant contribution from infill wells and well interventions on total production potential for the Statfjord Field during 2001. Although the size of the remaining oil accumulations is decreasing, there is still producible oil remaining in all reservoirs. The oil is mainly found in structurally complex areas, poor quality sandstone or wedged between the emerging gas- and waterfronts. The distribution of remaining oil is a result of several individual drainage histories, resulting in a large variation in fluid contacts within each reservoir and hence a complex distribution of oil accumulations. At present the average field water cut is above 80%, the gas-oil ratio is increasing, and both injection and liquid production are limited by process capacity on the platforms. Historical production for the Statfjord Field through December 2001 is illustrated in Figure 4. Production History. Since its discovery in 1973, more than 280 wells have been drilled on the Statfjord Field. About 340 production logs and 220 saturation logs have been acquired. At present the activity level on Statfjord is higher than ever, with a drilling schedule comprising 15 infill wells drilled per year and more than 100 annual well interventions. There are currently 124 active wells in the field, and no spare slots available. Therefore all new wells are drilled as sidetracks from existing wells. Figure 3 illustrates the significant contribution from infill wells and well interventions on total production potential for the Statfjord Field during 2001. Although the size of the remaining oil accumulations is decreasing, there is still producible oil remaining in all reservoirs. The oil is mainly found in structurally complex areas, poor quality sandstone or wedged between the emerging gas- and waterfronts. The distribution of remaining oil is a result of several individual drainage histories, resulting in a large variation in fluid contacts within each reservoir and hence a complex distribution of oil accumulations. At present the average field water cut is above 80%, the gas-oil ratio is increasing, and both injection and liquid production are limited by process capacity on the platforms. Historical production for the Statfjord Field through December 2001 is illustrated in Figure 4.
- Europe > United Kingdom > North Sea > Northern North Sea (1.00)
- Europe > Norway > North Sea > Northern North Sea (1.00)
- Geology > Structural Geology > Fault (0.48)
- Geology > Geological Subdiscipline > Stratigraphy (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
- Europe > United Kingdom > North Sea > Central North Sea > Ness Formation (0.99)
- Europe > Norway > North Sea > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > Tampen Area (0.99)
- (20 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- (3 more...)
Abstract This paper discusses how the challenge to improve production from a depletedoil field in Algeria was approached using an advanced Coiled Tubing DrillingSystem. The paper covers the planning and implementation of the project anddiscusses lessons learned, results and conclusions. Introduction The Rhourde El Baguel (REB) oilfield has been on production since the early1960's. Only 20% of reserves (estimated at 2 billion OOIP) have been recoveredto date. Approximately 84 wells have been drilled in the field so far, mostlyvertical. In the reservoir, matrix properties vary from moderate to very poor, with permeabilies in the range 0.02–10 Md. It can be generally classified as atype II Fractured Reservoir. As production is dominated by flow fromsubvertical natural fractures, the challenge was to drill horizontally andintersect regularly spaced conductive fracture swarms (see Fig. 11). Thereservoir is highly depleted, having a pressure of 1800 psi at 2900m TVD (EMW3.64 ppg) - the original reservoir pressure at discovery was approximately 5600psi. The Cambrian sandstone is extremely hard and abrasive: with compressivestrengths ranging between 15,000 psi up to 35,000 psi (see Fig. 1). There isalso a high degree of stress anisotropy, and borehole breakout was a majorconcern for both the drilling and production modes. This paper describes how the project was evolved, planned and implemented tosuccessfully meet these technical challenges by sidetrack drilling, underbalanced out of existing well bores with the completion in place whilealso meeting stringent heath, safety and environmental challenges.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.61)
- North America > United States > Kansas > Drift Field (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Berkine Basin (Trias/Ghadames Basin) > Rhourde El Baguel Field (0.99)
- Well Drilling > Well Planning (1.00)
- Well Drilling > Pressure Management > Underbalanced drilling (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- (11 more...)
Abstract Horizontal wells with continuous reservoir sections between 10,000 and 20,000 ft are being used for the development of the laterally extensive lowpermeability chalk in the Dan/Halfdan oil accumulation, offshore Denmark. The concept, design and practical experiences from an efficient andeffective completion and stimulation method, Controlled Acid Jet (CAJ), which has been developed to stimulate very long horizontal well sectionsin a single operation, is described. It is a non-cemented liner, with a limitednumber of unevenly spaced holes (perforations) which ensures efficient acidstimulation of the complete reservoir section, provided the acid is pumped atsufficiently high rates. The CAJ liner has in several ways set new standards for the completion andstimulation of long horizontal wells. The most significant achievement with theCAJ liners is the remarkably effective acid coverage with efficient stimulationof reservoir sections up to 14,400 ft in a single operation. This is more than20 times the interval length covered during matrix acid stimulation in atraditional cemented and perforated liner. The CAJ liner completion and stimulation concept has proven to be efficient, uncomplicated to install and very cost effective. Currently, 35 CAJ liners areproducing from more than 220,000 ft of reservoir sections in the Dan WestFlank/Halfdan field. The production performance of the wells completed with the CAJ system isconcluded to be superior to the performance of wells completed withconventional systems. Introduction and Background History of the Dan/Halfdan Oil Field The Dan/Halfdan oil field, located about 240 km off the west coast ofDenmark in the North Sea, is operated by M rsk Olie og Gas AS on behalf of DUC(Dansk Undergrunds Consortium, a partnership between A.P. Møller, Shell Olie ogGas Udvinding BV (Holland) and Texaco Denmark Inc). Oil production from the Danfield (STOIIP 2.8 MMMstb) started in 1972 and has now increased to a level of120,000 stb/d. The discovery of a significant extension of the oil accumulationon the West Flank of the Dan field has previously been described.The 29,600 ft long MFF-19C well, with a horizontal reservoir section of 20,749ft, followed the oil accumulation more than 700 ft down dip from the main fieldand below the structural saddle point. This led to the discovery of a 1.5MMMstb non-structurally trapped oil accumulation, i.e. Halfdan. See SPE 71322for further details. Reservoir Description The Dan/Halfdan field in the southern part of the Danish North Sea compriseschalk reservoirs of Danian and Maastrichtian age. The development focus is onthe Maastrichtian reservoir. The reservoir is characterised by relatively highporosity (typically 25–35%) and low liquid permeability (0.1–2 mD). The bottompart of the Danian, the D2 unit, exhibits relatively low porosities and verylow permeabilities. The Danian and Maastrichtian formations are separated by azone with extremely poor permeability, the so-called Danian-Maastrichtianhardground. Figure 1 shows a typical log from a vertical well.Properties of the chalk vary on a 3–7 ft scale, reflecting depositional cycles, which can be recognised over long distances in the lateral sense. Each cycleconsists of a high and low porosity interval, causing the significant verticalporosity variations. Well Concepts used on the Dan Field The Dan field was initially developed with deviated wells, stimulated withacid or sand propped fractures. In 1987, the first horizontal wells weredrilled and, encouraged by their production performances, the fieldwas thereafter exclusively developed with horizontal wells. History of the Dan/Halfdan Oil Field The Dan/Halfdan oil field, located about 240 km off the west coast ofDenmark in the North Sea, is operated by M rsk Olie og Gas AS on behalf of DUC(Dansk Undergrunds Consortium, a partnership between A.P. Møller, Shell Olie ogGas Udvinding BV (Holland) and Texaco Denmark Inc). Oil production from the Danfield (STOIIP 2.8 MMMstb) started in 1972 and has now increased to a level of120,000 stb/d. The discovery of a significant extension of the oil accumulationon the West Flank of the Dan field has previously been described.The 29,600 ft long MFF-19C well, with a horizontal reservoir section of 20,749ft, followed the oil accumulation more than 700 ft down dip from the main fieldand below the structural saddle point. This led to the discovery of a 1.5MMMstb non-structurally trapped oil accumulation, i.e. Halfdan. See SPE 71322for further details.
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5505/17 > Dan Field (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5505/13 > Halfdan Field > Maastrichtian Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5505/13 > Halfdan Field > Danian Formation (0.99)
- (2 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics (1.00)
Abstract A system has been developed and tested that reduces the production from zones producing high water cut in open hole screen completions. By use of flotation balls with neutral density in formation water, the system automatically reduces a nozzle area on each joint with increasing water cut. The oil selective inflow control system (OS) is used to reduce flow from zones that significantly contribute to the water cut in a well. A reservoir simulation tool has been configured to incorporate the OS functionality. Introduction Most oil wells that penetrate more than one reservoir zone or penetrate long reservoir intervals may benefit from inflow control to limit water and gas production. Sliding sleeves or smart well systems are expensive and time consuming to install and are proven to pose reliability challenges, flow area constraints and other limitations. Inflow control devices (ICD) (passive chokes or capillary flow paths) have been used in long horizontal wells primarily in the Norsk Hydro Troll Field with success to delay gas coning. By sizing the chokes, the sandface pressure along the wellbore is made more uniform. This results in better areal drainage. ICDs were in the Grane field simulated with ECLIPSE and NETool reservoir simulation software, but did not provide gains in production rates or ultimate recovery to increase the NPV of the field. This is mainly decided by high oil viscosity and the larger importance of water influxes in Grane, than on Troll. It was decided to study the possibilities and impact of an Oil Selective inflow control system (OS). A test and simulation program was set up between EWS and Norsk Hydro to verify the functionality and operational limitations for an OS in the Grane field. The Grane Field Grane is operated by Norsk Hydro and lies in the southern part of the North Sea, Norwegian Sector. The reservoir has excellent reservoir properties.
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Statfjord Formation (0.99)
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Lista Formation (0.99)
- Europe > Norway > North Sea > PL 169 > Block 25/8 > Breidablikk Field > Hod Formation (0.99)
- (17 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Flow control equipment (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (2 more...)
Abstract A finite-difference, lumped-parameter based, reservoir-wellbore coupled model was developed to characterize the economic benefit of inflow control devices on horizontal well completions. Baker Oil Tools' inflow control device (ICD), the Equalizer™, has been tested and analyzed as a standalone entity. Several correlations have been developed to quantify the pressure drop characteristics of this ICD. To show the positive effects an ICD has on an asset, one must quantify, not only the flow performance of the ICD, but the time dependent depletion scenarios of the reservoir in question. In this paper, the benefits of a unique inflow control device will be shown by analyzing reservoir depletion scenarios with and without inflow control. Without inflow control, a horizontal completion is at risk of early water breakthrough. With early water breakthrough, the water cut tends to escalate due to its lower viscosity compared to that of oil. As the water cut escalates, oil production drops significantly, often leading to shutdown of the well and reserves being left in the ground. This paper will show the benefits of using an ICD by describing the model development of a hypothetical, yet typical, field and the subsequent analysis that drives the completion design of the horizontal well. The model includes the reservoir, water oil contact, near-wellbore characteristics, wellbore, sand control screen, ICDs, basepipe, and production tubing, capital expenditure input, and real time calculations of net present value of the reservoir. The use of inflow control devices increases the capital expenditure, but the increased cost is more than compensated for by the increased production efficiency. The technology presented can be extrapolated and applied to the analysis of well completions consisting of different types of hardware. Future developments of this type of analysis will be described. This work provides three additions to the technical knowledge base of the petroleum industry; 1) use of a lumped-parameter finite-difference based model to couple the wellbore completion to the reservoir, 2) proof of the positive effects of inflow control devices on producing hydrocarbons, and 3) further information on using the "economics of reservoir depletion" to drive horizontal completion designs. Introduction Horizontal wells have become an established method of recovery for oil and gas. In reservoirs where these fluids occupy strata that are horizontal, or nearly so, a horizontal well offers greater contact area with a productive layer than does a vertical well. Larger contact areas allow lower drawdowns to recover more oil or gas. Economics aside, these facts imply that a horizontal well should be as long as possible. However, frictional effects in the wellbore limit the useful length of a horizontal well. Frictional effects can be significant in long horizontal wells in high permeability reservoirs. In such cases, the drawdowns are low and they are of the same order of magnitude as the frictional pressure drop in the well. If wellbore pressure drop is not taken into account in such cases, the productivity of the well can be grossly overestimated. Wells in reservoirs with an aquifer and/or gas cap face the risk of early breakthrough of water or gas. Ignoring wellbore pressure drop would make the engineer assume that the encroachment of water/gas is uniform towards the horizontal well along its entire length. But in reality, encroachment is skewed and fluids tend to break through first at the heel of the well. The only way to quantify those effects is by including the wellbore pressure drop in the calculations. The phenomenon of uneven flow distribution in the reservoir caused by frictional pressure drop in a horizontal well can be seen in Figure 1.
- North America > United States (0.28)
- Europe > United Kingdom (0.28)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Flow control equipment (1.00)
The Integration of Intelligent Well Systems into Sand Control Completions for Selective Reservoir Flow Control in Brazil's Deepwater
Hill, Leo E. (Baker Oil Tools) | Ratterman, Gene (Baker Oil Tools) | Lorenz, Mike (Baker Oil Tools) | Fonseca, Sergio (Baker Oil Tools) | Moreira, Oswaldo (Baker Oil Tools) | Fernando, Machado (Petrobras) | Izetti, Renaldo (Petrobras)
Abstract This paper describes the integration of intelligent well system technology into a conventional, open hole sandface completion for the purpose of selective flow control in a deepwater reservoir. In deepwater subsea applications, the ability to remotely control the inflow of water can eliminate costly rig intervention while extending well life and increasing recoverable reserves. The planning, testing and installation of these technologies will be detailed in this paper. Deepwater Brazil continues to be a region where technology which addresses inherent cost and risk can favorably impact financial performance. The horizontal gravel packed completion was introduced in deepwater subsea Brazil in 1998. To date, over 67 successful subsea horizontal gravel packs have been installed in both production and injection wells. To further enhance deepwater financial performance offshore Brazil, installation of a Level 6 multilateral well in the Campos Basin occurred in 1999. Given the demonstrated success of open-hole horizontal gravel packing, and the fact that this technology is now relatively mature, additional completion capability in the way of effective, selective zonal isolation has become desirable. Addressing this challenge is the application of diverter valve technology. This technology has been successfully used in 8 subsea wells in the Campos Basin during the year 2001. Combined, zonal sandface isolation and the long reach of horizontal wells provide operators with the ability to selectively drain a reservoir(s) and move the development cost per barrel oil equivalent (BOE) downward. The fully electric intelligent well system consisting of 3–1/2" and 5–1/2" smart selective flow control devices was deployed on land in the Mossoro Field. The purpose of the installation was to prove the technology before transferring the application into the deepwater subsea environment. These valves were operated remotely from the office location. After months of successful actuation and data acquisition, the system was pulled and prepared for installation into a deepwater subsea well. During the land based well test, it was deemed necessary to modify the volumes of data stored. Software modifications were made to optimize the rate of data storage. In order to integrate the Intelligent Well System into the sand control completion, a process of optimization was necessary to meet well construction and operational requirements. This process was inclusive of well path design to reach the targeted well location while controlling the dogleg severity to allow placement of the intelligent well system It included completion design to achieve selective flow control and minimize operational risk during installation. This is the first application of an all electric, remotely operated intelligent well system integrated into a sandface completion for the purpose of reservoir production management. Introduction Well designs for subsea field developments in water depths of 2000+ meters have unique requirements. Nearly 70% of Brazil's oil &gas reserves lie beneath deepwater (300- 1000m) and ultra-deepwater (>1000m). The successful exploitation of these reserves depends on the processes and technologies by which they can be safely, yet economically extracted in an environmentally sound manner. The economics of reducing well count while accessing the same targeted reserves and eliminating the high cost of re-entry are what make the utilization of intelligent well systems attractive. The integration of IWS into an environment requiring well lifetime sand control and zonal isolation has required an evolution of technology.
- South America > Brazil > Rio de Janeiro (0.47)
- North America > United States > Texas (0.46)
- North America > United States > Louisiana (0.28)
- South America > Brazil > Campos Basin (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Sul Field > Macae Formation (0.94)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Sul Field > Lago Feia Formation (0.94)
- (2 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Sand Control > Gravel pack design & evaluation (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells (1.00)
Abstract We assess the impact of control enabled by far-field monitoring of bottom-water encroachment on the production performance of horizontal wells. Monitoring can be achieved by electrical measurements distributed along well length against the formation. We assess the depth of investigation resulting from such measurements. Inflow control is achieved by means of downhole valves in a segmented horizontal completion. We examine the impact of valve placement, inflow configuration, and mode of operation on production performance. The combined monitoring and control problem is illustrated by means of synthetic examples. Introduction There are several reasons that motivate analysis of the monitoring and control problem with respect to horizontal wells. First, the realization that frictional losses in horizontal wells induce nonuniform influx, even if the formation is free of geological heterogeneities. Second, the observation from logging-while-drilling and production logging that long horizontal wells traverse multiple geological facies and exhibit nonuniform inflow profiles. Third, the recognition that horizontal wells are the primary vehicles for the development of subsea and deepwater assets, where aversion to intervention motivates use of monitoring and control systems. Monitoring configuration is dependent upon mode of control, which can be passive or active. Passive control aims to counter unfavorable inflow profile by some geometrical modification of the completion configuration. Passive control can be implemented in a variety of ways including - liner completion with stinger tubing, liner completion with labyrinth screens, branched liners as in multilateral wells (penetrating a single formation), and cased completion with preferential perforating or fixed chokes. Passive control is effective when the distribution of formation properties such as permeability and connectivity to external drives (aquifer, gascap) is well known. Surface sensors are adequate for passive control. Active control can be envisaged in reactive and proactive modes. Reactive control consists of actuation of control device when inflow profile sensed by wellbore sensors cannot be reconciled with production constraints. This might take the form of rate cutback at surface (e.g., surface choking or reduced pumping due to excessive gas/oil ratio), or rate cutback downhole (e.g., zonal choking by discrete or continuous valves or zonal shut-off due to rising water-cut). Wellbore sensors such as downhole flow monitoring systems can be used for this purpose. Proactive control consists of actuation of control device prior to the vigorous arrival of displacing phases in the wellbore as a means to circumvent or delay degeneration of production performance. Proactive control is control in anticipatory or preventive mode. It stems from the notion that it is most effective to control the flow field before the displacing phases invade the region of acute pressure gradient in the neighborhood of the wellbore. Proactive control requires deployment of sensors that can monitor the flow field away from the wellbore. Distributed electrical arrays can be used for this purpose. (Other distributed sensors may also be applicable.) Application of electrical arrays in waterflood monitoring has been reported in the literature; here we examine their application to ameliorate the production performance of horizontal wells under bottom-water drive. Analysis of this problem requires a methodology to couple the problems of monitoring and control.
- Asia (0.94)
- Europe (0.66)
- North America > United States > Texas (0.46)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Drilling exploration wells in deepwater or other frontier environments is an inherently expensive process. The effects of non-productive time caused by bad or less informed decisions are magnified in such costly and difficult environments. A major operator is using the communications, presentation software, and other real-time technologies to build a more effective collaborative team to support its deepwater exploration program in the Gulf of Mexico. The technology to remotely monitor drilling operations has long existed. From its inception, the goal of this Real-Time Operations Center (RTOC) has been to move beyond mere monitoring to participation in the drilling operation. A team of drilling experts, with an average experience level of 20+ years, was assembled. They were given the tools and facility to have 24/7 contact and visibility with all drilling operations. Additionally, the prospect teams associated with each project began holding their meetings in the Real-Time Operations Center, involving both the rig (via video conferencing) and the expert team in ongoing planning and operational decisions. The shift from the old paradigm of a reactive team gathering to sort out existing problems, to a proactive team focusing on preventing problems has had a major impact on drilling operations. This paper will describe the technology, people, and processes employed to build this Real-Time Operations Center. The layout of the control room and the integration of the data collection and control/decision making processes will be discussed. The skills required and work processes designed to avoid a feared ‘big brother’ syndrome are described. These steps were taken to overcome people and process issues that can defeat such an initiative. Communication and decision making procedures were outlined, designed, and implemented to facilitate success. Success and the documented value of this project are described. Introduction Highly experienced and knowledgeable people have always been a key ingredient of successful drilling operations. With the advent of widespread real-time technologies and the drastic cost reductions seen in deploying these technologies, Shell Exploration and Production Company (SEPCo) initiated this project with the goal of further leveraging the available expertise. Some basic infrastructure required was already in place. The remote offshore locations are connected to the operator network via available microwave or satellite links. The drilling and other relevant data is being collected, transmitted, replicated, and managed using Halliburton Sperry-Sun's dynamic data management service. The major new steps required involved 1) setting up a facility in the operator's office, 2) assembling the proper team to staff it, and 3) designing and implementing work processes that allowed this to be a constructive and valuable effort. The implementation team determined that the best location for the Real-Time Operations Center would be at SEPCo's main office in New Orleans, on the same floor as the drilling operations and planning team. Although this created space constraints for building the facility it was felt that the advantages of having immediate access to the proper people required whenever collaborative decision making needed to take place far outweighed any other considerations. The team members, whose input to the processes are only required on an as needed basis could comfortably work on their usual duties and rapidly assemble to the RTOC when required.
- Well Drilling > Drilling Operations (1.00)
- Management (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Data integration (0.41)
Abstract Continuing reservoir management at mature stages often concentrates on delineating pockets of remaining mobile oil. This is becoming a major task for reservoir geologists and petrophysicists. Many old fields are coming up as investment targets for reactivation and there is general consensus that modem techniques can lead to additional recovery of between 10 and 20 percent. However, there are many pitfalls which can render an apparently attractive project into an economic failure. This paper will discuss the non-technical screening criteria related to reservoir architecture, accumulation condition and production history. Mobile remaining oil can be found in a number of predictable locations in reservoirs depending on their structural style and facies. Attic oil along faults is perhaps the most simple configuration but sizeable volumes of remaining oil can also occur as a function of reservoir stratification and lateral discontinuity. A systematic overview of the different types has been compiled based on structural or stratigraphic lateral continuity and vertical reservoir connectivity. This leads to four main types with some sub-groups for each of which screening criteria have been derived on the basis of field examples and models. The screening criteria specify minimum conditions which may lead to economic re-development with horizontal side-tracks from existing wells. In addition recommendations are given with respect to data gathering to confirni the presence of economically viable targets. P. 345
- Europe (1.00)
- North America > United States > Texas (0.66)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Geology > Structural Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
- Geology > Geological Subdiscipline > Stratigraphy (0.67)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.48)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
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- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
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