Owing to the increasing water cut and decreasing in reservoir pressure of the well, the oil production of the well has seized and the well has become dead. This research study evaluates the implementation of the artificial lift methods ESP and Gas Lift- economically and technically on the well by using the production performance software (PROSPER) and economical yardsticks (NPV and ROI). The theory, design, production forecast, capital and operating expenditures of the electric submersible pump and gas lift are discussed for the appropriate selection of any of two options. The PROSPER software is used as the simulation tool for the design and production forecasting of the ESP and Gas Lift based. The ESP and Gas Lift methods have been simulated for the design and production forecast by entering the reservoir and completion inputs in the software. Subsequently, the software has been simulated to run on different sensitivities of the variables such as water cut, wellhead pressure setting depth, operating frequency and gas injection rates to check the production rates at different scenarios. Having performed the production performance simulation on the selected artificial lift methods, the methods have been investigated by capital budget-ing. In capital budgeting, the capital and operating expenditures of both lift methods were evaluated by determining their discounted value (NPV) and re-turn on investment (ROI). The prime objective of the research is to accomplish maximum production rates and profitability by selecting the most appropriate artificial lift method for the well; as a consequence it is concluded that the suitable artificial lift method for a well can be selected by applying the simulation and economical schemes.
Fluid loss is one of the biggest problems faced by the drilling engineers; the drilling fluids invades in the formation resulting in the fluid loss, which increases the overall cost of the drilling. The objective of this study is to use biodegradable natural ingredients as fluid loss additives in oil-based mud as the industrial based polymers which are normally used as fluid loss agents are highly expensive. In this study, corn starch and sugarcane bagasse ash were used at 1, 3, 5, and 7% wt./wt. separately as fluid loss additive in Oil-based mud. The drilling mud mixed with 1% of SCBA yielded the best result for fluid loss. Similarly, corn starch at 1% wt./wt. exhibited the best fluid loss characteristics. However, their effect on other mud properties was; plastic viscosity, apparent viscosity, yield point, and gel strength increased with increasing the concentration whereas, they have no or little effect on pH and mud weight.
The producing behavior of low permeable gas condensate reservoirs is dramatically different from that of conventional reservoirs and requires a new paradigm to understand and interpret it. As the reservoir pressure initiates to decline and reaches to dew point pressure of the fluid then the condensate is formed and causes the restriction in the flow in the reservoir rock which results, decrease in the well productivity near the wellbore vicinity which is known as condensate blockage. Henceforward, it is better to understand the behavior of the low permeable lean and rich gas condensate reservoirs by several perspectives through the compositional simulator. Besides this study involves the following perspectives; the increase in the number of wells and by varying the flowrate of the gas in six different cases for low permeable lean and rich gas condensate reservoirs. It was concluded that low permeable lean and rich gas condensate reservoirs have similar gas recovery factors. Whereas the CRF plays inverse behavior for both reservoirs as CRF is maximum for lean gas condensate at single producing well but for rich gas condensate reservoir the CRF increases as the number of wells escalates. Additionally, in second effect the varying gas flowrates lean gas condensate reservoir has maximum CRF at lesser flowrate but it is opposite for the low permeable rich gas condensate reservoir, for single or two producing wells the flowrate effect plays but when the number of wells is increasing there is not any significant change in CRF
Well completion is the process of construction a well geared up for production or injection. This mainly involves preparing the bottom of the hole to the required conditions, running the production tubing and associated downhole tools. Production from a multizone well can be obtained from a single tubing string as well as from dual tubing strings but it depends on pressure difference, depth and fluid present in the formation. This paper is based on the optimum well completions design for a multizone well of the Tal block region which contains four reservoirs of different formations: Lockhart (limestone), Hangu and Lumshiwal (sandstone), Samanasuk (limestone) & Datta (sandstone) having pressures of 7432psia, 7563psia, 7843psia, and 7982psia respectively. The well is producing four zones (multilayer well) and the generated numerical model for each completion (single string multizone completion and dual string multizone completion) shows better performance and economic feasibility.
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