Over 85% of Petroleum Development Oman (PDO) production is water and without action, this may increase to 95% by 2012. In 2004, a Chemical Profile Control (CPC) team was launched to coordinate a 2-year trial deployment of chemical water-shut-off technologies across the company. The aim being to reduce unwanted water or gas ingress for the purpose of improving oil or gas production while securing target recovery. The deployment of chemical systems is adversely affected by four major challenges, namely;limited know-how, especially of petroleum engineers & well engineers,lack of multidisciplinary approach to candidate & chemical selection,proof of concept before deployment and,definition & measurement of success. To tackle this problem, CPC team began by grouping PDO's Water Shut-Off challenges into 8 problem statements and presented it to known global providers. A workshop was organized inviting all contractors to propose solutions to the stated problems and acquaint PDO with available solutions. Based on our findings and confirmatory laboratory tests, the CPC team developed a Heatmap, which is a solution matrix that matches problems with solutions. A multidisciplinary assessment team was also created responsible for reviewing every project and proposing realistic solutions. Since then more than 33 well trials - mainly in carbonate formations - have been completed at over 52% success rate using 3 existing contractors. Encouraged by these results, the company awarded umbrella contract to 3 other contractors to deploy a wider range of systems expected to boost success rate. The company strongly believes that increased success rate can be achieved by exploiting wider choice of effective systems, as inspired by laboratory trials. This paper, therefore, presents the strategy, team, methodology, and overall results of the trials to date. 1. Introduction PDO asset can be classified into Northern & Southern Directorates. The Northern directorate produces at an average of 85% water cut and is dominated by carbonate fields under extended waterflood and Enhanced Oil Recovery (EOR). There are a few clastic formations. The hydrocarbon is not very heavy or too viscous, ranges from 45–30 APIGR and .5–50cp excluding the EOR assets. Most wells in North Oman are sub-hydrostatic and are either gas lifted or produced with Electric Submersible Pumps (ESPs). However, in the South, average water cut is over 90% and is coming from mainly clastic formations consisting of heavy and viscous hydrocarbon ranging from 30–15 APIGR and 10–600cp. Most South Oman wells are equally sub hydrostatic and are lifted with either ESPs or Beam Pumps (BP) or sucker-rod pumps. Altogether, the total water production from both northern & southern assets amount to about 3.6 Million barrels per day, a significant percentage of which is unwanted water. In the past several years, a number of water shut-off treatments have been applied in PDO with conflicting and discouraging results. Since 1998 to date more than 300 cements jobs have been completed in matrix and fracture applications. More recently foamed cement has also been tried. About 30 profile control jobs were carried out in 1992 using the Relative Permeability Modify (RPM) or Self-Selective-Systems (SSS) while 6 other jobs in 1993 on fracture shut-off using polymer gels solutions, including Marcit/Maraseal™ water shut off campaign between 1996 – 98. In all these applications, only marginal success was noted in south Oman while North Oman carbonates are known for higher success rate but with inconsistent outcome. Other variants explored include Matrol 3+™ which proved successful but too expensive for sustainable use. The Ritin polymer also showed a favorable response but needed more attention in system design. On a general note, PDO had a better handle of cement solutions than chemical systems probably due to less complexity of cement based systems. Cement applications have proven more successful but never last long enough to sustain their Net Present Value (NPV). The reason for their short life is low imbibitions of cement into matrices, hence the need for particle-free systems.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn early 2000 the success rate for matrix stimulations matched the industry average of around 30%. In mid-2000 an integrated approach was launched, covering all aspects of the stimulation process, and today the success rate for engineered stimulations stands at 85%. This successful approach has been maintained over the past two years and enables new technology to be effectively introduced into the process and opens up additional opportunities. Long term sustained gains have been achieved allowing stimulations to become an effective tool for reservoir management.Examples of successful applications are included below.
Over the years there have been numerous attempts at establishing a key performance-measuring index (KPI) that would allow comparisons to be drawn with drilling activities in different locations. In the case of drilling fluids no model has gained any universal acceptance and measuring performance in this activity has typically been left to the 'easy to acquire' cost/m or cost/m3 per interval drilled on a campaign well basis within a specific field. Drilling fluids cost across the oil industry range between 5–25% of the well construction costs. If we continue with the traditional cost focused indices then at the low end of this range there is no visible incentive to reduce costs and hence no drive to measure nor improve performance in many of our locations. The real drivers to improve performance lie with the impact on the overall well performance and field development economics in terms of Non Productive Time (NPT) and deferred or impaired production and these can be significant. A pragmatic approach is being developed within Petroleum Development Oman (PDO) that embraces the importance of NPT data as a measure of drilling performance and addresses the issues of production performance of the well to identify well improvement opportunities. This paper reviews the existing mud performance parameters and their drawbacks, presents a practical prediction technique for drilling mud cost based on existing offset field/well data which is less complex than the typical functional drilling cost models (Kaiser 2007)1 and describes how to integrate mud-related cost factors into a simple Mud Quality Index (MQI) equation. The underlying assumptions and limitations of the new KPI will also be discussed to determine any further improvements deemed necessary. Using real data from some PDO fields, MQI data was generated for a group of wells and compared to the old mud cost matrix data to show the disparity in the wells performance ranking based on the different KPIs. The KPI tool is expected to facilitate drilling fluids planning, design and management decision-making on the capital-intensive exploration, deep appraisal and development drilling projects when fully deployed. Introduction Although drilling fluids direct costs are a fraction of the well drilling costs, their associated costs in terms of Non Productive Time (NPT) and deferred or impaired production are potentially much higher when overlooked. The importance of NPT data as a measure of drilling performance is underscored in the Shell Quality Well Delivery Process (QWDP)2 which places a premium on the NPT data analysis for identifying well improvement opportunities. The process also identifies robust KPIs which recognise well production delivery i.e. Unit Development Cost (UDC), ﹩/expectation developed reserves, and Production Attainment (PA) - Actual Production/Planned Production in addition to the traditional ﹩/ft drilled for measuring well performance. Equally important is the formation damage potential and the impact on deferred production and project economics. For technical reasons an Oil Based Mud (OBM) system may be selected to facilitate drilling in highly reactive shale formations as they offer greater lubricity in deviated/horizontal holes with better rig time optimisation than a Water Based Mud (WBM). But OBM systems potentially may be more damaging across the reservoir due to emulsion and wettability effects. Most mud engineers would prefer using an OBM for the superior technical drilling performance and ease of maintenance but they are seldom concerned with the post completion well performance and hence the properties of the mud may not be maintained to minimise this damaging effect. Including well damage data in fluid performance measure can correct this service defect.
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