No abstract

Optimizing the development of oil and gas fields necessitates the use of accurate predication techniques. The predictions should also involve minimizing the uncertainties associated with day-to-day operational challenges related to wells, pipelines and surface facilities. The choke size settings, for instance, need to be frequently adjusted to optimize production flowrates using the right techniques. This paper provides a method to optimize the production flowrate for existing wells and to minimize the cost through finding the best cost-effective selection. Providing an insight into factors affecting the flow assurance of oil and gas reservoirs is also included. The study has been implemented by the use of nodal analysis conducted by a surface network simulation, to reach the optimum design of oil and gas production systems. The optimization of the wells can be achieved by changing tubing and flowline sizes, minimizing the skin factor, controlling the water cut, and adjusting the gas-lift injection pressure. The Hurricane oil field that covers a wide range of subsurface and surface facility data is simulated in this paper. Seven reservoirs are considered in this study containing eleven different wells. Seven of these wells are producing naturally while the remaining four wells are gas-lifted. For each of the eleven wells, different parametric scenarios are run on the different size of the pipelines and chokes. Flow assurance study has been conducted to know the effect of severe slugging, wax deposition, and hydrate formation. Severe slugging has been predicted using a surface network simulation, while wax deposition and hydrate formation using a pressure-volume- temperature (PVT) simulation. For the artificial lift wells, as this field was mainly operated by gas lift, a new design has been implemented based on gas surface injection rate as a way to eliminate the workover operations.

Formation damage resulting from organic and inorganic depositions, such as calcium carbonate, asphaltene and paraffin, is one of the most commonly encountered types of damage in the oil and gas industry. These depositions are usually associated with a decrease in crude productivity, accelerated failure of production completions, such as from electric submersible pumps (ESPs), and less footage coverage while running with production and flow profile logging tools. The major concern highlighted is the increased probability of having more organic deposits in the wellbore as a result of the increased scale of the inorganic deposits. A thick, heterogeneous sludge mix of hydrocarbons and solid materials is a critical subject for characterization and solubility measurements. Analyzed deposit samples were collected either while running with production logging tools, when pulling out a failed ESP, or when lowering the completion equipment. The hydrocarbon phase was removed by organic solvent and the precipitated solid materials were collected for a lab analysis and solubility test. The solid phase analyses included X-ray diffraction (XRD) analysis and scanning/transmission electron microscopy (SEM and TEM). The composition of organic deposit samples was investigated using saturates, aromatics, resins, and asphaltenes (SARA) characterization, Fourier transform infrared analysis (FTIR) and Fourier transform ion cyclotron resonance mass spectrometry (FTMS). The sludge sample solubility tests were conducted over a variety of organic solvents at different temperatures, up to 300°F with a solid mass/liquid volume ratio of 1:10. The paper presents a typical analysis procedure of organic deposits collected from downhole equipment. The XRD analysis of solid debris materials (inorganic) present in collected sticky materials samples showed that the materials contained mainly carbonate compounds; for instance, calcite-CaCO3, dolomite-CaMg(CO3)2, and Halite-NaCl. These materials were completely soluble in acids like 15 wt% of HCl at reservoir conditions. Calcite scale would have been a problem in cases where the calcium content exceeded 12,000 mg/L. Low solubility results were obtained with static reaction of organic solvents recipes with the sticky materials around 17 to 50 wt%. This, in turn, increased solubility up to 98% as observed from the reaction in dynamic conditions.

This paper discusses a method for optimizing production facilities design for onshore/offshore wells during new field development. Optimizing the development of new oil and gas fields necessitates the use of accurate predication techniques to minimize uncertainties associated with day-to-day operational challenges related to wells, pipelines and surface facilities. It involves the use of a transient multiphase flow simulator (TMFS) for designing new oil and gas production systems to determine the feasibility of its economic development. A synthetic offshore oil field that covers a wide range of subsurface and surface facility data is considered in this paper. 32 wells and two reservoirs are considered to evaluate the effect of varying sizes of tubing, wellhead choke, flowline, riser, and transport line. A detailed investigation of the scenario of emergency shutdowns to study its effect on the system is performed using TMFS. Other scenarios are also evaluated such as startup, depressurization, pigging, wax deposition, and hydrate formation. This paper provides a method to minimize the cost by selecting the optimum pipelines sizes and diameters, and investigating the requirements of insulation, risk of pipeline corrosions and other related flow assurance parameters. Different facility design scenarios are considered using TMFS tool to achieve operational flexibility and eliminate associated risks. Pressure and temperature conditions are evaluated under several parametric scenarios to determine the best dimensions of the production system. This paper will also provide insight into factors affecting the flow assurance of oil and gas reservoirs.

Fiber-optic sensing (FOS) technology is gradually becoming a pervasive tool in the monitoring and surveillance toolkit for reservoir engineers. Traditionally, sensing with fiber optic technology in the form of distributed temperature sensing (DTS) or distributed acoustic sensing (DAS), and most recently distributed strain sensing (DSS), distributed flow sensing (DFS) and distributed pressure sensing (DPS) were done with the fiber being permanently clamped either behind the casing or production tubing. Distributed chemical sensing (DCS) is still in the development phase. The emergence of the composite carbon-rod (CCR) system that can be easily deployed in and out of a well, similar to wireline logging, has opened up a vista of possibilities to obtain many FOS measurements in any well without prior fiber-optic installation. Currently, combinations of distributed FOS data are being used for injection management, well integrity monitoring, well stimulation and production performance optimization, thermal recovery management, etc. Is it possible to integrate many of the distributed FOS measurements in the CCR or a hybrid combination with wireline to obtain multiple measurements with one FOS cable? Each one of FOS has its own use to get certain data, or combination of FOS can be used to make a further interpretation. This paper reviews the state of the art of the FOS technology and the gamut of current different applications of FOS data in the oil and gas (upstream) industry. We present some results of traditional FOS measurements for well integrity monitoring, assessing production and injection flow profile, cross flow behind casing, etc. We propose some nontraditional applications of the technology and suggest a few ways through. Which the technology can be deployed for obtaining some key reservoir description and dynamics data for reservoir performance optimization.