Water production in a hydrocarbon-producing well greatly affects the economic feasibility of a well, in worst cases, resulting in the well being shut in. Therefore, an effective water-control treatment program is important to help control water production and maintain or increase hydrocarbon production. Relative permeability modifiers (RPM) can be implemented in some high-water-cut wells as a chemical treatment to selectively reduce water production. The study in this paper introduces an RPM system that is a hydrophobically modified, water-soluble polymer. This polymer is adsorbed on the rock surface, resulting in the alteration of the characteristics of rock surfaces. The unique polymer chemistry selectively reduces the water's effective permeability in the reservoir, impeding water flow and facilitating increased hydrocarbon flow. It can also help enhance the reservoir drainage area. Core-flooding experiments were conducted in the laboratory to assess the performance of the RPM system. Experiments were conducted on synthetic cores and formation cores from a well in the Central Arabia field. The laboratory experiments showed that the RPM system can drastically help decrease water permeability, with low regained water permeability and high regained oil permeability in a synthetic core. The water regained permeability was 17% (i.e. 93% reduction in water permeability) in a formation core using formation oil and water. High-permeability core plugs were used in the laboratory to determine the effectiveness of the RPM system. A detailed procedure was followed, including repetitive oil and formation water cycles, to determine core permeabilities. The results demonstrate that the RPM system is effective in the Central Arabia sandstone formation. This paper discusses the study performed to implement an RPM system in a Saudi formation, where the treatment can effectively reduce water flow in the treated area with minimum damage to hydrocarbon flow. The RPM system can be customized based on the temperature and permeability of the treatment zones to achieve maximum reduction in water production.
Drilling and completing wells for hydrocarbon production comprise the major cost of well operations. Slim-hole drilling can significantly reduce drilling costs, making low producing reservoirs economically viable. However, a number of challenges are associated with slim-hole wells. A major challenge encountered while deploying lower completions in long horizontal slim-hole wells is stuck pipe, as the wellbore diameter is less than six inches, allowing restricted clearance between the wellbore and completion equipment. Stuck pipe incidents can cause significant non-productive time (NPT), additional high costs, and the possibility of compromising the well objective. Stuck pipe incidents may require sidetrack operations in the worst cases, which may considerably change the planned well design and delay the overall project, along with increasing costs. Drilling in the minimum stress direction with heavy mud weight and high overbalance pressure adds to the challenge in deploying completions in HPHT slim-hole wells. While deploying the lower completions in slim-hole wells, many factors come into play and each factor has a critical role in the success of the operation. After conducting a detailed study on several HPHT slim-hole gas wells in Middle-East region, a risk matrix was developed for a specific well-bore diameter, by identifying some common variables. Based on potential chance of occurrence, a certain value was assigned to each variable. The risk mitigation plans are driven by the risk matrix variables. Using this risk matrix, the occurrences of stuck pipe incidents in critical HPHT slim-hole wells that initially tend to have high chances of stuck pipe were significantly reduced. The risk matrix presented in this paper successfully mitigated stuck pipe incidents from occurring and has saved millions of dollars in associated costs. The matrix played a key role in operator's drilling operations and was adapted in operations as an important tool to evaluate final wellbore conditions prior to selection of the optimum completion type. This paper presents a highly effective risk matrix that significantly minimizes stuck pipe incidents during drilling/completion operations of slim-hole gas wells.
A brief introduction about floating docks, its advantages and types have been described. The naval architectural considerations which play a significant role in the design of floating dock have been explained. Typical ratios of L/B and L/D as a function of Dock’s lifting capacity have been presented. Empirical formulation for the same have also been indicated wherever applicable. Intact stability and its criterion as applicable for a floating dock have been described. Critical positions during evolution of docking operation and important considerations while performing stability calculations have been highlighted. Attention has also been drawn to the damage stability of floating dock. Aspects of longitudinal and transverse bending moment, which are the governing aspects in the scantling calculations have been described. Also typical methods for securing and mooring of floating dock, without compromising on flexibility for docking operations have been described. Methodology and consideration which has to be kept in mind while using design software (such as NAPA) have been indicated. Simple size optimization techniques which result in steel / ballast volume reduction have also been explained.
Hydraulic fracturing is a well stimulation process used to maximize production of oil and natural gas. It is used to create new fractures and enhance in-situ subsurface fracture systems as well to allow oil or natural gas to move more freely from the rock pores to the production wellbore. The post-fracturing flowback procedure is critical to the production performance of a fractured well. An improper flowback cleanup often leads to lower retained conductivity near the wellbore, resulting in reduced production. Controlled flowback is beneficial for properly removing polymer gel residue from the proppant pack. The degree of propped fracture cleanup is related to a number of factors that relate to the measurement of guar polymer contained in the fluid flowback samples. Measurement of guar carbohydrate from fluid flowback samples is used to estimate the amount of guar recovered after fracturing treatments. Using a field study and laboratory analysis, this paper demonstrates that the measurement of the guar polymer in fluid flowback can be used as an indication of fracture cleanup. The Anthrone method, a technique for measuring total guar carbohydrate in the fluid flowback samples, is used. Anthrone dissolved in sulfuric acid forms a yellow solution. In the presence of guar or its derivations, the solution turns green/blue. Using an ultra violet (UV) spectrometry technique, guar concentration in the fluid flowback samples can be determined from the intensity of measured color. Many fluid samples collected from two wells were analyzed and results are presented. A good correlation between the guar polymer concentration and cleanup is observed and quantified. Results from this study show that using this technique can result in an optimum flowback design that maximizes near-wellbore (NWB) conductivity and fracture cleanup for better production.
In unconventional and tight-gas reservoirs, hydraulic fracturing treatments are widely performed to recover significant amounts of hydrocarbon, thus establishing unconventional plays as commercially viable. However, in gas reservoirs, formation damage and various unfavorable conditions, such as condensate banking, phase trapping, water-blocking, etc., can cause production that is less than expected. This paper introduces a new fracturing fluid additive that aims to help increase production following a hydraulic fracturing treatment and helps control fracture face damage. The new surfactant in the fracturing fluid system can allow faster production at higher rates. It can also provide a better regained permeability after hydraulic fracturing because it reduces formation damage caused by phase trapping and improves mobilization of liquid hydrocarbons, including condensate. The product has been typically designed for unconventional reservoirs, including tight gas, tight sandstone, shale, and coalbed methane. Coreflooding experiments were conducted to demonstrate the performance and efficiency of this new additive in fracturing fluid and to optimize its concentration. Favorable results were obtained from the experiments that indicated good formation damage control in terms of regained permeability along with significant condensate production after the fracturing fluid treatment. The additive, when used in specific concentrations, has physical and chemical properties that contribute to improving hydrocarbon production by enhancing the mobilization of liquid hydrocarbons. It tends to reduce the capillary pressure and surface tension of the treating fluid to allow higher fluid mobility in the treated reservoir zone. This effective new fracturing fluid system is environmentally friendly and exhibits excellent performance under high-temperature/high-pressure conditions. The fracturing fluid additive presented here helps overcome a condensate banking problem and unfavorable conditions, such as wells coming online slowly and low production rates resulting from formation damage following hydraulic fracturing treatments. Experiments validate the performance of the fracturing fluid additive, and significant condensate production for optimum additive concentration was observed during experimental treatments.
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