With an initial reservoir pressure of 911bar and a downhole temperature of 170 o C Kristin is the first HPHT field in the world that has been completed and produced using subsea solutions. CaCO 3 scale has been identified as the major production problem due to the expected high draw down from the reservoir together with the high level of bicarbonate and calcium in the formation water. In April 2007 breakthrough of formation water in two of the wells were detected and the subsurface safety valve in one of them showed increasing inertia. In August/September 2007 the first combined scale dissolver & squeeze treatments were carried out in these two wells. This culminated after more than 5 years of testing of a large variety of chemicals and operational planning. The jobs were successfully carried out using the unique HP injection system on board that is dedicated for such well intervention. In this paper a full case history of these first treatments on Kristin will be presented. It starts with a brief summary of the difficult path to qualify various chemicals for the challenging conditions. This is followed by the early detection, diagnosis and data interpretation processes when the formation water first broke through. The paper will include the operational planning with special focus on the constraints to inject chemicals at an adequate rate against a HPHT well. The challenges in delivering and maintaining separation of the different chemical pills to a well lying 7km away will be highlighted. Despite the best intension some compromises on the treatment design have to be made in order to maintain safety and system integrity and these will be discussed. Finally the paper will conclude by presenting the results from these treatments, the assessment of the operations, the experiences being learnt and the area identified for future improvement.
Dissolver technology has been developed and applied with varying degrees of success over the past few years to clean carbonate and the more challenging sulphate/sulphide scales from production tubing and process equipment. A common question that is often raised but which has no published experimental work to provide an answer is "under what liquid to solid ratio would a sulphate dissolver not be effective to clean production tubing?" A set of experiments were conducted at a range of temperatures to review the impact of surface area/mass to fluid volume ratio for barium sulphate scale. The surface area/mass to fluid volume ratio were measured from 13 examples of scaled or partially scaled production tubing in an attempt to understand why in some laboratory tests dissolvers used to remove sulphate scale appear to show better performance than is observed in the field. This paper shows that simple dissolver tests, when performed with high volume/volume ratio (1 part scale to 45 chemical) which equates to a mass to liquid volume ratio of 1:10 which is most commonly used in screening studies, can give misleadingly high performance information as they show enhanced dissolution rates and mass of scale dissolved. In fact, from the 13 scaled pipe sections examined in this work, a much higher ratio of solid mass to liquid volume (10:1 to 1:1) (equating to a volume/volume ratio of 1:4.5 to 2:1) is more typical and with these ratios dissolver performance is greatly reduced. The results from these experiments are used to give a guide as to the measured liquid to solid ratio where sulphate dissolvers have the potential to work for barium and calcium sulphate scales and to where mechanical removal of the deposit would be the better treatment option.
Scale is a major problem for the oil and gas industry and is often controlled by the use of downhole scale inhibitor squeeze treatments. The placement of scale inhibitor in acid fractured limestone reservoirs presents a particular challenge and effective placement of scale inhibitor cannot be guaranteed when performing conventional low rate (<10bpm) bullhead squeeze treatments. In order to ensure the fluid package is placed over the whole of fractured interval it is necessary to perform high rate scale squeezes (40–60bpm) in conjunction with mechanical divertors. However, these treatments are expensive and limit the amount to treatments that can be performed per day in a scale squeeze campaign. This paper describes the development of a range of viscosified polymeric scale inhibitors for squeeze application in acid fractured wells. A particular feature of these products is their viscous self diverting nature which means they can be used at low pump rates at rates of <10bpm. This method also precludes the use of mechanical divertors and enables cross flow problems to be overcome and effective chemical placement over the whole of fractured interval. In addition, this offers the benefit of improved scale control and squeeze lifetimes coupled to considerable economic savings by being able to perform more treatments per day using conventional pumping equipment. A detailed investigation into the rheological properties of selected products has been performed to design the optimal delivery system. Experimental data on the compatibility of a variety of viscosifying agents and chemical breakers different types of polymeric scale inhibitors will be presented. This will include viscosity profiles, shear thinning behavior and breaking times for these systems. Inhibitor performance and core flood studies to evaluate formation damage potential and retention and release characteristics will be also be presented. In addition, the paper will add the results of a computer modelling study to validate the experimental data and aid the placement strategy for optimum field application. Introduction Oilfield scale is a key issue in the petroleum industry where vast amounts of water are used and co-produced with hydrocarbons. The formation of mineral scale can create a range of problems including; reduction in pipe carrying capacity, increase in operational hazards due to blocked valves, localization of corrosion attack, impedance of heat transfer, and increases in operating costs due to down time and system maintenance.
Oilfield scale formation is dependent upon the production of water and as a result most scale inhibitors are water soluble and deployed using an aqueous phase. For treatment of wells that produce only small amounts of water and/or have water sensitive matrices and wells with high water cuts with lifting problems the use of an aqueous inhibitor can cause many problems. Even with the development of oil miscible and emulsified scale inhibitors the same problem can be encountered when the incorrect screening procedure has been used in the laboratory. This study describes the development of a range of truly oil soluble scale inhibitors for squeeze application. A particular feature of these materials is that they preclude aqueous phases and are soluble in crude oil and diesels. The products have been designed so that is possible to deploy calcium sensitive scale inhibitors in a non-aqueous medium. Upon contact with formation water passing the near wellbore the scale inhibitor will partition into the water phase and undergo a precipitation reaction. This provides a mechanism for potentially increasing treatment lifetime. In addition, the scale inhibitor precipitation can be further controlled and enhanced through emulsification with a calcium loaded aqueous medium also containing organic additives to aid and enhance the precipitation process. Although this involves incorporating water into the product package the invert emulsion provides an oil continuous matrix and is still considered to be significantly less damaging to water sensitive formations than standard oil dispersible and emulsified scale inhibitor packages. A detailed investigation into the properties of selected oil soluble and emulsified products has been performed. Experimental data on compatibility with production fluids, thermal ageing, oil/water partitioning, inhibitor performance, extent of precipitation and core flood studies to evaluate formation damage potential and retention and release characteristics will be presented. This paper will also highlight how the use of the oil soluble precipitation process can increase squeeze lifetimes when compared to traditional aqueous squeeze treatments. In addition, a new core flood procedure for the screening and evaluation of non-aqueous chemical treatments will be described and the implications this has for field application of these products will be discussed. Introduction Oilfield scale is a key issue in the petroleum industry where vast amounts of water are used and co-produced with hydrocarbons. The formation of mineral scale can create a range of problems including; reduction in pipe carrying capacity, increase in operational hazards due to blocked valves, localization of corrosion attack, impedance of heat transfer, and increases in operating costs due to down time and system maintenance.
Heidrun is recognised as a challenging field for scale management due to the combination of water injection, high barium and clay content, and unconsolidated sandstone formations. A selection and qualification process for scale inhibitor squeeze in this field followed the standard laboratory testing protocols. A novel scale inhibitor chemistry was qualified and field trialled; however, introducing the new scale inhibitor chemistry to the field was more challenging than anticipated. The technical qualification was successful but the field trial resulted in lost productivity, halting field-wide implementation. The field trial started in Well I and indicated good scale protection but gave considerable loss of productivity. This paper presents the lessons learned through an extensive laboratory investigation to identify specific factors influencing the issues observed with the field trial. Furthermore, work completed to qualify a solution for iron-rich formations is described. It was determined that the inhibitor was leaching iron from minerals in the reservoir and forming an insoluble complex with the metal, particularly at mildly acidic pH. While elevated iron concentrations were seen in flow-back samples from other wells across the field, these did not approach the levels observed for Well I which was producing from a geological formation rich in iron-bearing minerals. The field trial was successful in less iron-rich formations and the product was implemented field-wide for such reservoir zones. The scale inhibitor was designed to offer strong chelation, a property suited to scale inhibition and reservoir retention, but this was also a significant factor in the productivity loss. This important finding dictated that Product A should be regarded as unsuitable for reservoir zones containing iron-rich minerals. Subsequently, an alternative scale inhibitor was technically qualified and has since been successfully field trialled and implemented in the iron-rich formation. This selection exercise for Heidrun posed challenges in terms of reservoir retention and iron compatibility for field-wide implementation of new chemistry. Overcoming these issues gave valuable insights for future qualifications of the novel scale inhibitor chemistry.
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