Wellbore clean up has become an integral part of well completion operation aiming to maximize well productivity from a near skinless wellbore. The awareness has become more widespread with more and more horizontal and sand packed openhole wells being completed with so-called non damaging Drill-In-Fluids (DIF). Although drill-in-fluids control fluid loss and saturation related damage to a great extent, they tend to leave a sticky filter cake containing polymers and Calcium Carbonate particulates which can severely restrict well flow. Acids, oxidizers, chelating agents and enzymes have been often used as wellbore clean up fluids with mixed success. This article demonstrates laboratory and field evidences on superior efficiency of some recently developed bio-enzymes and explains the reason of their not so satisfactory treatment result in some wells.Simulated Reservoir Condition Core Flow (RCCF) and return permeability measurement was the basis of laboratory evaluation and comparison of various clean up formulations, including inorganic/organic acids, oxidizing agents, various enzymes and combination treatments. Mud filter cake was developed by simulating drilling and reservoir parameters. Cleaning treatments were mimicked as per realistic field operation. Photographic evidences were produced on clean up efficiency and final conclusion was drawn based on return permeability.Well treatment methodologies are discussed and production data from over twenty wells/legs were produced, analyzed and compared. An effort is made to analyze unsatisfactory treatment outcome in some of the enzyme treated wells and to establish the best practice approach for wellbore clean up operations.
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.
Radioactive material contaminated, hard crystalline scale deposition on ESP & downhole equipment was resulting in frequent breaking of ESP shaft in a multilateral openhole producer. Extremely high workover cost in frequent replacement of downhole equipment and associated radioactive hazards, necessecitated a strategic MDT approach. Software usage and extensive laboratory backup helped finding the best possible option to mitigate this problem. Three possible well treatment options were investigated. Scale inhibitor squeeze option was studies through reservoir condition core flow and rejected because of probable formation impairment and placement difficulties in a complex well and reservoir geometry. Periodic soaking of ESP with scale dissolver was considered a viable option because of economics and operational ease. Laboratory studies were conducted to design the placement strategy. We developed a xanthan based high viscous self degrading polymer gel coushion which would support the scale inhibitor solution around the ESP for the necessary soaking period to prohibit flow into the pressure depleted formation. However this concept had to be abandoned because of flipping over of the fluids in laboratory observation and uncertainty of optimum soaking period downhole. The last and final option was to wait for the running ESP to fail and during workover the well could be completed with a macroni line for continuous injection of scale inhibitor. Judicial selection and optimization of inhibitor, continious monitoring of well treatment and well behavior has resulted in phenomenal success which is demonstrated by the fact that the ESP run life has been exceeded 700+ days against <100 days average runlife prior to treatment. The treatment also took care of radiation hazard and contaminated equipment disposal problem to a large extent. Introduction Inorganic scale build up inside the wellbore and near wellbore formation can smother a well in a very short productive period causing additional operating expenses in the range of millions of dollars. This statement is particularly true if the deposited scale is contaminated with NORM (naturally occurring radioactive materials). In addition to loss of production and workover cost, the full set of contaminated tubulars and downhole equipment needs to be either decontaminated at designated site or to be disposed following international regulations. Both the options are undesirable from the operational complication and expenditure point of view 1,2,3. Origin of NORM in oilfield scale - The NORM radionuclides are uranium, potassium, thorium, radium and radon. These elements are found in trace quantities throughout the earth's crust. These unstable radioactive elements undergo periodic decay and results in the formation of elements with different physical and chemical properties. Radium-226 which is a decay product of U-238 and Th-230 is water soluble and may therefore be found dissolved in aqueous phase associated with oilfield produced water. As far as radioactive scales are concerned, Ra-226 is the most common element responsible for radioactivity which is co-precipitated with Gr-II elements, particularly with barium as carbonates or sulphates. RaSO4 and BaSO4 have similar solubility and crystal structure hence Ra2+ substitutes for Ba2+ in the BaSO4 lattice. At lower temperatures RaSO4 is less soluble than BaSO4, increasing Ra substitution. There may be cases where Pb-210 is also a minor contributor 4. These types of radioactivity are also called TENR (technology enhanced natural radioactivity)4. This paper describes the laboratory and field experience, success achieved and lessons learned in dealing with radioactive strontium scale deposition and associated problems in BRH oil field.
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