The Yibal Shuaiba field, Oman, has been developed by pattern water flood and infill drilling. The field has produced 185 million m3 (30% of STOIIP) with 1996 average production at 34,000 m3/d, 60% from horizontal wells. This domal structure carbonate reservoir is characterized by complex faulting systems and limited lateral fluid movements. This and the significant reservoir offtake have developed complex reservoir water movements which has a major impact on future development opportunities in addition to the surface congestion and risks associated with the overburden formations. Horizontal wells with 3D seismic assistance have offered, compared to vertical wells, more effective means for addressing such opportunities and managing the field. The experience build-up coupled with active technological trials have resulted in:–Improved productivity (PIF of 3) through effective stimulations, zonal isolation and increased drainage area,–Improved recovery through the ability to look for and target un-swept oil, delayed coning and more effective high density infill development.–Optimised water injection through better distribution.–Improved economics through cheaper (sidetracking) and less wells and higher production rates.–Enhanced safety and environmental protection through less overburden penetration and limited surface locations. The above has resulted in a complete turn to horizontal producing wells coupled with a change in the development approach to target remaining oil and provide the injection where needed rather than following the equally-spaced pattern infilling. The Horizontal well development is a building block to the previous vertical pattern development with limited expansion. The equally-spaced vertical pattern development have been utilised to achieve lower well costs through sidetracking of watered-out wells and also used as a guide to target the un-swept areas between the vertical producers. Similarly, horizontal wells will form the basis for future developments through lateral sidetracks from existing horizontal holes. This paper highlights the benefits of horizontal wells in a mature field development and the potential benefits of further advancements. Introduction The Yibal field is situated in the North of Oman, 300 km southwest of Muscat, on stream in 1969. The main producing reservoir is the Shuaiba carbonate with a STOIIP of 600 million m3. The reservoir, the Upper Shuaiba formation, is composed of Lower Cretaceous carbonates, deposited on a shallow marine shelf. It forms a low relief domal structure with an areal extent of some 70 km2 at ca. 1400 m beneath the surface. This structure is transected by mainly NE-SW and NW-SE faults and fractures which are the result of deep salt movements and the collision of the Arabian and Eurasian continental plates. A significant amount of these faults and fractures are open and conductive to water flow. This created the challenge to successfully complete horizontal wells penetrating such features. The reservoir permeability is low (1 – 100 mD) with low viscosity (0.6 cp) and light (40 API) oil. The field was initially produced under depletion drive. In 1972, a five-spot lateral water flooding (injecting into the oil column) pattern development was started. In the early 1980's, simulation studies led to a shift to bottom water flooding (injecting below the 50% water saturation level). Further field development was based on infill drilling (Fig. 1) supplemented by pattern bottom water injection to increase recovery. Inverted nine-spot (500 m well spacing) infilling was started in the 1980s, followed by quarter pattern infill wells (between the corner producers and the centre pattern injectors). P. 223
PDO is managing some 850 Electrical Submersible Pump (ESP) systems scattered across North & South fields, which is continue to grow in the next five years business plan. All ESP wells have real time down-hole sensors that measures intake and discharge pressures, intake and motor temperatures, vibration and current leakage. The oil producing fields are equipped with real time data transmission system where several data measurements; down hole (such as pump intake and discharge pressures and temperatures) and surface (such as volts, amps and frequency) are transmitted directly from the well site to the gathering stations, central control rooms and even to the engineers' desktop. At present, PDO is deploying an integrated smart tool which will monitor, control, and optimize oil production and ESP performance to the various disciplines involved in oil production and optimization like Reservoir and Petroleum Engineers, Programmers, and Field Operation Teams. However, in order to enable these modern well surveillance systems, which often produce an overwhelming quantity of information but the data is often misleading or difficult to interpret, establishing the Pattern recognition of the trended real time data is key to make the software intelligent enough to be effective to the work places. This paper will demonstrate how precise ESP, well and reservoir performance can be predicted from simple physical relationships and how these relate to the trends of surface and downhole data. A number of real field examples of data trends will be shown to illustrate how a proper understanding of these patterns will allow prompt ESP troubleshooting and ensure the correct actions are taken. The results are correlated with equipment pull and inspection reports to validate the diagnosis. Pattern recognition trends and analysis will be presented for common problems such as hole in tubing, shut in at surface, ESP wear, blockage at pump intake, debris in pump, broken shaft, change in reservoir pressure, blockage at perforations, etc. A proper understanding of these trends will allow the correct settings of alarm and trips and assist in the implementation of semi-automated well surveillance and diagnostic system which being currently deployed in the Company. A pattern recognition analysis check sheet will be included in the paper to allow users to quickly interpret data trends and diagnose well, ESP and reservoir performance problems.
North Oman comprises four mature assets, producing 90% of its oil from old wells. In the drive to enhance oil production of the existing well stock, while arresting the natural decline of oil rate through better Well and Reservoir Management (WRM), well intervention work has increased in importance in the Company's portfolio of activities. From 2003 a robust subsurface Well Intervention program is rigorously generated and vigilantly implemented and closely tracked. In 2005, some 3,600 well work activities were executed in the areas of Well Surveillance (well and reservoir data gathering); Well Optimization (oil generating activities, i.e. additional perforations, water & gas shut-off, stimulations, etc); Well Restoration (to maintain the old wells' oil potential by ESP replacements, tubing wash, re-dress Gas-lift valve, etc) and Well Integrity (production casing repairs, fishing operations, annulus pressure testing) activities. Implementation of this program calls for utilization of various types of intervention technologies such as work-over hoists, electric / normal coiled-tubing units, electric wireline units, slick-line units and non corrosive pumping units. The oil generating (optimization) activities delivered some 5.4%, while restoration and integrity repair activities safeguarded some 23%, of the total oil production from North Oman, there by arresting the natural oil rate decline during 2005, at a low unit technical cost per barrel. As the fields get older, the well intervention work is expected to grow in term of magnitude, complexities, need for new technologies, cost impact and new challenges. Hence, the directorate has foreseen a need for continued concentration on improving the management of the well intervention to maximize the value realized in terms of oil reward and arrest of the natural decline oil rate. This paper describes recent improvements to the Well Intervention Management Process in the North oil fields; from ranking of the activities, resource planning and optimization; activities planning and scheduling; execution of the plan, tracking of the operational / reservoir performance and feed back of learning for further improvement. These improvements are described by real examples of well interventions and the results achieved from managing the overall well intervention operations. It will also discuss the current operational challenges and limitations, and new technologies needed to address the issues. Introduction North Oman, comprising four major mature assets (clusters), produces nearly 50% of Company's net oil. As the fields continued to age, oldest being over 40 years on production, wells management challenges from reservoirs to the surface.
Petroleum Development Oman LLC (PDO) production activities rely significantly upon artificial-lift technology due to the nature of the reservoir fluids and properties. Currently, about 90% of the wells require some method of artificial-lift in PDO. Many existing and future wells will eventually produce with more challenging or high GOR conditions which results in technical and economic challenges to select the appropriate artificial-lift method, as well as, the well completion configuration. Conventional ESP applications are ideal for high production rate wells with moderate gas rates. Gas lift applications often target medium to low production rate wells and can easily tolerate high gas volumes. Within PDO, gas lift conversions to ESP are growing more common due to reasons related to facilities constraints (e.g. gas compression / injection gas volume, aging compressors, gas flow-lines integrity, etc), declining reservoir pressures due to ineffective water injection or increasing water cut. As a result, some new ESP wells are now producing at higher GOR. For field developments, artificial-lift concept selection is often one of the key decisions to be assured at the concept selection milestone. In marginally-economic fields, the choice of artificial-lift method can easily erode the project value, especially owed to significant uncertainties with regards to potentially high producing GOR risks. In fact, this was demonstrated during the development planning process for a high GOR field which is generically referenced in this paper as field T in North of Oman with an initial solution GOR of 216 Sm3/m3. In this particular case, artificial-lift selection was based not only on economical terms but also on technical and operational feasibility aspects. Based on current PDO's experience to date operating high GOR wells, the ESP method was identified during the study as the preferred artificial-lift method for field T. An ESP feasibility evaluation was completed and included a detailed assessment of the expected range of free gas at the well pump intake depth for the entire field production life-cycle. This evaluation considered the completion configuration, as well as, gas-handling and separation equipment limitations. By adjusting the well and reservoir field management plan for field T and incorporating the latest PDO experience and learning's to date, the study provided the technical basis to assure feasibility of the proposed development plan for the expected high GOR producing environment. Further economic assessment of the artificial-lift selection decision, which is not detailed in this paper, supported a significant impact to the project on the order of 1/3 of its expected value. This paper summarizes the range of PDO operating experience to date with ESPs installed in high GOR conditions. Additional details are shared regarding the feasibility study for field T including supporting rational for the artificial-lift selection for the project concept selection, proposed well completion concept design and the artificial-lift economic evaluation. Finally, established best practices for high GOR fields and key challenges going forward will be discussed.
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