TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA common characteristic of "challenging" unconventional gas resources, namely low permeability sands, shale and coal bed methane, is that the ultimate recovery is dependent on economic removal of liquids accumulation, generally termed "deliquification". This resource is making up an everincreasing part of the North American gas supply. Since there is no one "perfect solution", and the problem affects thousands of wells, the opportunity involves not only technology development but also knowledge management and building resource capability. This paper outlines the scope of impact and opportunity in North America, followed by the industry's approach and progress in the arena. The North American industry is working a variety of deliquification technologies for "challenging" gas, with developments ranging from adapting existing oil-field technologies, to developing gas-specific technologies, to "on the horizon" technologies. Examples in each stage of the development process will be shown.The effective communication of these developments to operators and suppliers is also a necessary component. The industry-wide annual conferences that have emerged in the last seven years are the primary avenue for this communication, and are supplemented in some cases by operator internal networks.This combination of technology development and effective communication is increasingly allowing North American operators to maximize the recovery of challenging gas resources.
Summary This paper introduces a new systematic way to evaluate gas well deliquification options throughout the life of a well by using power as the most general measure of cost. As a gas well depletes, the gas velocity declines to the point that liquid droplets are not removed from the wellbore. Liquids accumulate and impose increased pressure on the sandface. To maintain production, we apply artificial lift. In some cases, such as plungers or foamers, we make better use of the remaining reservoir energy. In other cases, we apply external energy using methods such as gas lift or pumps. Improving gas well recovery by removing wellbore liquids accumulation is of interest to industry in two general ways. First, there is the perennial question of how to select deliquification techniques for the entire life of the well. This paper provides a framework to compare the relative merits of various artificial lift systems through final depletion. Furthermore, stakeholders are demanding more substantial bases for booked reserves, and with more development this method offers a defensible estimation of the economic limit with respect to liquids accumulation that honors the depth, productivity, and completion characteristics of a particular well. To understand the appropriate application of artificial lift power, we proceeded in two stages. First, we modeled a synthetic two-phase gas well including the liquid-loading behavior. The model produced the familiar result of natural flow in early production followed by lower production as the well declines and liquids accumulate. Next, we compared using the well's energy (i.e., siphon or velocity tubing strings) to the addition of external energy (i.e., gas-lift injection and downhole pumps) to optimize production at every stage of the depletion. We used the theoretical external power as a proxy for well operating cost to calculate the economic limit. Ultimate recovery was improved by the addition of external energy. In particular, pumping was found to be favored over gas lift, because it provided lower bottomhole pressures and required less power, thereby yielding higher production at any point in time along with a lower economic limit rate.
Understanding ranges of reservoir depletion is essential in optimizing field development within tight gas plays. Unfortunately, determining reservoir pressure in low permeability reservoirs is difficult due the long shut-in times required for conventional pressure transient analysis. Pre-fracture injection tests have successfully been used in low permeability reservoirs, but these tests can add operational complexity restricting their use in many cases. Horizontal wells with reservoir pressure below hydrostatic are particularly challenging since running downhole pressure gauges prior to fracture stimulation is often deemed to be an unacceptable risk. New low cost, low risk measurement methods for determining reasonable approximations of reservoir pressure in horizontal open-hole packer/sleeve (ball actuated) completions have been successfully tested in an East Texas Cotton Valley well. This paper describes two of the methods used in this well which successfully yielded reliable approximations of reservoir pressure. The primary driver for using these methods was well risk imposed by extended deployment of pressure gauges downhole. The first method, port opening observation, is applicable to open-hole packer/sleeve completions where the first port is pressure activated. The second, gas-over-level, can be used on any type of completion on an under-pressured formation where the risk or expense of downhole pressure gauges is prohibitive. It approximates sandface pressure which can then be analyzed using standard DFIT (diagnostic fracture injection test) methods. Both of these methods can be performed with minimal cost and operational interference thus providing an opportunity to routinely obtain reasonable estimates of reservoir pressures during infill horizontal drilling programs.
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