The work completed was a comprehensive approach of understanding and treating formation damage to further redevelop a mature asset through successful remediation operations. The identification of skin was completed with slickline techniques and reservoir and production flow profile monitoring. Primary formation damage mechanisms were naturally occurring scales in the near wellbore, damage caused by water blockages and workover fluids. Redesigned completion fluids, acid pumping and innovative coiled tubing tools were used in the remediation works which were all firsts in the basin. A modified decline curve analysis technique was used to economically justify treatment of nearly all wells in the field and led to substantial production increases.In 2003, an Association was formed to manage a mature Romanian gas field producing since 1970. Production skin was evident and in 2010 a well failed due to halite formation. Consequently, liquid and solid sampling tools were deployed within suspect wellbores. In 2010, a new workover fluid formulation was introduced but despite improvements formation damage was still induced. From 2010 to 2013, there had been an increased focus on understanding and treating calcite, halite and water block damages to boost field-wide productivity.Formation damage was observed as being both naturally occurring and induced in the field. An initial assessment and pilot treatment of 10% of the wells led to a near 40% incremental gain in those wells. After which, the campaigns were further expanded to over 75% of the field. Technically, the investigation into formation damage changed the development plan for the field going forward. Operationally, the intervention procedures introduced were new to the basin and have been adopted by the Association's partners in other assets.A major limit on ultimate recovery from depleted hydrocarbon reservoirs is declining well productivity. Salt formation, scale deposition, and water blockage restricts flow, reducing production rates and ultimate recovery of reserves. Therefore, economic formation damage management is an essential tool for extending field life, increasing profitability, and improving recovery of aging assets. Impressive results led to a strategic shift in local field production management and the techniques are useful worldwide in similar fields.
Sabriyah and Raudhatain are the main fields producing from the Middle Marrat Jurassic formation in North Kuwait with approximately 5 km distance between the two fields. Raudhatain fluid is considered as Volatile Oil, while Sabriyah is described as Gas-condensate. 16 PVT samples from Raudhatain were analyzed and described as Volatile oil. 12 PVT samples taken from Sabriyah field where 7 samples show gas condensate behavior and rest shows volatile oil. A key challenge in understanding the Sabriyah fluid characterization is the fact that 5 well samples that showed Volatile oil behavior are not separated from the Gas condensate wells by any apparent barrier. In addition, the initial reservoir pressure is much higher than the saturation pressure, preventing the equilibrium of those fluids. The objectives for this study are to analyze the physical explanation of coexistent of oil and gas-Condensate in one communicated reservoir with reservoir pressure higher than saturation pressure, apply different modeling approaches to accurately describe the fluid behavior in Sabriyah field and finally capture the influence of uncertainty in the type of fluid on the production forecast. The physical explanation for this phenomenon was investigated from different points of view: the variation of temperature, compositional variation with depth, existence of geological barriers, and facies changes. It was found that the compositional variation with depth and the change of fluids with changes of facies can provide reasonable explanation for this phenomenon. The first explanation related to compositional variations with depth is supported by the observed data that shows a strong relationship between depth and fluid type, while the temperature did not influence significantly the gas-oil phase change. The second explanation related to the concept of gas and oil charge depending on facies is supported by mercury injection capillary pressure data taken from different depth in the reservoirs, this concept improves the understanding of fluid distribution which could not be explained in previous approaches. This paper shows the way of modeling this phenomena based on these two explanations, which honor both static and dynamic data with special reference to the effect of these different modeling approaches on the production forecast of Sabriyah field. The near critical fluids which are the type of fluids in Sabriyah field are usually problematic to handle with Equation of State; therefore solving this particular case is expected to add technical value to reservoirs of the same type of fluids. The facies dependence of gas and oil distribution and the way of modeling this phenomenon is an innovative view that can contribute to the description of similar fields.
SUMMARYThe Laslau Mare field is located in the Transylvania Basin, Romania, is a multi-reservoir, brown gas field, vertically split in 6 production packages with different fluid contacts and pressure levels; shale intercalations divide the reservoir layers from each package in several separated sandstone or shalysandstone bodies; to add complexity the two upper packages have high water production risk and the lower packages have low permeability as tight reservoirs. The field requires combining the latest technology from our side with the operational experience of ROMGAZ to refine the understanding of the reservoir and its productivity. The actual phase includes redevelopment and optimization of the field, with newer technologies and well interventions to insure profitable results. The Uncertainty management and Decision-making have contributed to the successful performance of the project and open another business opportunities. The fact that decisions facing eventualities and weak data were correct has been demonstrated with increased production, almost three times of its value on September 2003.
The most advanced technique to evaluate different solutions proposed for a field development plan consists of building a numerical model to simulate the production performance of each alternative. Fields covering hundreds of square kilometers frequently require a large number of wells. There are studies and software concerning optimal planning of vertical wells for the development of a field. However, only few studies cover planning a large number of horizontal wells seeking full population on a regular pattern. One of the criteria for horizontal well planning is selecting the well positions that have the best reservoir properties and certain standoffs from oil/water contact. The wells are then ranked according to their performances. Other criteria include the geometry and spacing of the wells. Placing hundreds of well individually according to these criteria is highly time consuming and can become impossible under time restraints. A method for planning a large number of horizontal wells in a regular pattern in a simulation model significantly reduces the time required for a reservoir production forecast using simulation software. The proposed method is implemented by a computer script and takes into account not only the aforementioned criteria, but also new well requirements concerning existing wells, development area boundaries, and reservoir geological structure features. Some of the conclusions drawn from a study on this method are (1) the new method saves a significant amount of working hours and avoids human errors, especially when many development scenarios need to be considered; (2) a large reservoir with hundreds of wells may have infinite possible solutions, and this approach has the aim of giving the most significant one; and (3) a horizontal well planning module would be a useful tool for commercial simulation software to ease engineers' tasks.
The most advanced technique to evaluate different solutions proposed for a field development plan consists of building a numerical model to simulate the production performance of each alternative. Fields covering hundreds of square kilometres frequently require a large number of wells. There are studies and software concerning optimal planning of vertical wells for the development of a field. However, only few studies cover planning of a large number of horizontal wells seeking full population on a regular pattern. One of the criteria for horizontal well planning is selecting the well positions that have the best reservoir properties and certain standoffs from oil/water contact. The wells are then ranked according to their performances. Other criteria include the geometry and spacing of the wells. Placing hundreds of well individually according to these criteria is highly time consuming and can become impossible under time restraints. A method for planning a large number of horizontal wells in a regular pattern in a simulation model significantly reduces the time required for a reservoir production forecast using simulation software. The proposed method is implemented by a computer script and takes into account not only the aforementioned criteria, but also new well requirements concerning existing wells, development area boundaries, and reservoir geological structure features. Some of the conclusions drawn from a study on this method are (1) the new method saves a significant amount of working hours and avoids human errors, especially when many development scenarios need to be considered; (2) a large reservoir with hundreds of wells may have infinite possible solutions, and this approach has the aim of giving the most significant one; and (3) a horizontal well planning module would be a useful tool for commercial simulation software to ease engineers' tasks.
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