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Abstract We propose to use pressure transient analysis to indicate the location of a flow restriction in a gas well and to characterize such a blockage. We have developed a transient simulator for a gas well with a single partial blockage at any location in the flowline. The early-time wellhead pressure drop is influenced by the volume reduction due to the plug and its location while the late-time steady flow wellhead pressure drops give an indication of the severity of the plug. Thus, the early-time and late pressure response data can be used for blockage detection. Our study found that the thickness, the length, the location, and the roughness of the plug strongly influence the wellhead pressure response. Of these factors, the extent of reduction in channel diameter (due to plug thickness) has the most effect. In addition, we found that the flow rate at which the test is run has a pronounced effect on both early and late time wellhead pressure transients. We also noted the influence of reservoir pressure on gas density and velocity, which in turn, have some effect on the wellbore storage and the frictional pressure drop. Our study showed that wellbore deviation did not have any appreciable effect on wellhead pressure drop. Geothermal gradient was also observed to have negligible effect on wellhead response. In addition, we found that for most scenarios, the transient pressure response characteristics for off-shore production are similar to those for on-shore wells. Thus, the analysis presented in this report is suitable for off-shore wells as well. Introduction Problem Statement. Unwanted flow restrictions are often a fact of life in the oil field. Potential causes for the development of these restrictions are numerous. Fluid properties, coupled with unfavorable pressure and temperature conditions, may lead to formation and deposition of wax, hydrate, asphaltene and scales on the pipe wall. Pipeline configurations could also lead to deposition of sand, buildup of liquid, or formation of vapor lock. Mechanical causes of flow restrictions include stuck spheres or pigs. Other possibilities include pipeline deformation from thermal stresses or mechanical damage. Once a blockage has occurred, the cause of the restriction is not always easily discernable. Delays in taking appropriate remedial action can cost lost production and could also lead to the development of hazardous situations. Administering the wrong remedial action to remove the plug can be very costly and may even make matters worse. Often, the type of blockage can be determined if the plug location is known. For instance, a pipe may collapse at a road crossing, or the temperature and pressure conditions in the line may be conducive for different solids deposition over separate but well defined regions. Knowing the blockage location could provide the additional information needed to determine the type of blockage with sufficient confidence to begin remedial action. P. 653
The generalized Newton-Raphson method is routinely deployed in industrial and academic applications in order to solve complex systems of highly nonlinear equations. Prime candidates for this solution methodology are complex natural-gas transportation networks, of which the nonlinear governing equations can be written in terms of nodal, loop, or nodal/loop formulations to solve for all network pressures and flows. A well-known issue of the Newton-Raphson iterative methodology is its hapless divergence characteristics when poorly initialized or when flow loops are poorly defined in loop or nodal/loop formulations. In this study, a method of linear analogs is discussed, which eliminates the need for user-prescribed flow or pressure initializations or loop definitions in the solution of the highly nonlinear gas-network governing equations. A comprehensive solution strategy based on analog transformations is presented for the analysis of a gas-pipeline network system comprised of not only pipes, but also common nonpipe network elements such as compressors and pressure-dependent gas supplies (e.g., wellheads). The proposed approach retains advantages of Newton-nodal formulations, while removing the need for initial guesses, Jacobian formulations, and calculation of derivatives. Case studies are presented to showcase the straightforward and reliable nature of the methodology when applied to the solution of a steady-state gas-network system analysis with pipeline, compressor and well-head components.
Long-term forecasts of gas field deliverabiIity are necessary for bothtransmission and producing companies in order to permit orderly planning offacilities and the development of reserves. A digital computer program has beendeveloped and is described herein. It is used to predict the availability ofpipeline gas over the producing life of a field or pool, to forecast the numberof wells required to deplete the reserves efficiently, and to schedule thedrilling requirements. The program also computes the amount of compression asit is required.
Included in the output data are the average reservoir pressure and shut-inand flowing wellhead pressures for each year. Maximum daily per well allowablesand average well deliverabilities are calculated. These results are derivedusing the linear relationship between reseryoir withdrawals and P/Z forvolumetric reservoirs and using the wellhead deliverability curve. The latterfunction is empirical in derivation and makes use of the exponentialrelationship between rate of flow from a well and the difference of squares ofthe static and flowing wellhead pressures.
A special aspect of the program is the well economics subroutine. Thisfeature enables the user to predetermine the limiting conditions that a wellmust satisfy in order to be considered economic to drill. The program willcalculate the present worth of future net production revenue from eachadditional well at any specified discount rate and, if the result isfavourable, the well will be added to the system and will yield a rate ofreturn greater than, or equal to, that specified in the input data. Producingcompanies often require a well to yield a total net production revenue which issome multiple of the capital investment in the well. This "well payoutmultiple" is left as a variable in the input data to accommodate individualcompany policy and to make provision for risk, amount of capital invested,expected productive life and other factors to be considered in investmentdecision making. Provision is also made in the program to establish a limit tothe maximum number of wells to be drilled in the reservoir.
Abstract Downhole Gas Compression (DGC) is the new form of Artificial Lift Technology used to increase the productivity of gas wells. Surface compressors are commonly used to reduce the pressure at the wellhead, which in turn reduces flowing bottom hole pressure, and boost the well productivity for a gas well especially during its decline phase when average reservoir pressure falls to a value equal to the pressure in the wellbore imposed by the sales line at the surface, plus the pressure losses that occur in the gathering system and the tubing. This conventional technique is not very efficient for the gas wells that produce significant amount of liquid (water or condensate), since this liquid needs to be separated before reaching the gas compressor. In addition, it also requires additional space for compressor assembly into the well, which may be very challenging for wells in offshore and subsea environment. As an alternative to surface compressors, down hole gas compressors technique can be applied to increase the well productivity, especially gas wells in offshore and subsea environment. Some study claimed that this new technology could: increase more than 30% of gas production; resolve many multiphase related issues; and delay the onset of liquid loading. However, numerous challenges associated with design, development and implementation of this new technology are not well understood or documented. This study has been focused to understand the key concepts of the technology and explore its potential application for increasing well productivity of gas wells through sensitivity studies. This paper presents principles mechanisms including theoretical background of DGC techniques, and results of sample case studies based on sensitivity analysis with aims to identify key factors to be considered for successful deployments of DGC into a gas well for natural gas reservoir. The paper also summarizes key findings which may be used as potential guidelines while considering for possible implementation of DGC technique during field development planning.