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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents results from a laboratory study comparing capillary pressure measurement techniques for tight gas sands. Included in our evaluation are the more traditional high-speed centrifuge and high-pressure mercury injection methods as well as the less conventional high-pressure porous plate and vapor desorption techniques. The results of our study show significant differences between the mercury injection data and composite capillary pressure curves constructed with data from the other three methods. Consequently, we have concluded that high-pressure mercury injection can be used to quantify pore size distribution, but often inaccurately characterizes capillary pressures, particularly at the irreducible water saturation. Moreover, our study suggests that a composite capillary pressure curve constructed from a combination of the vapor desorption data for the low water saturation range and high-speed centrifuge or high-pressure porous plate data for the high saturation range provides the most accurate capillary pressures for tight gas sands.

A theoretical calculation is needed to predict pump slippage in a rod pumped well. Slippage lubricates the pump plunger and barrel and prevents galling of metals. Additionally, an estimate of plunger slippage is necessary to calculate pump efficiency. Historical plunger slippage equations have been proven incorrect by recent testing. A new method for calculating plunger pump slippage in rod pumped wells is introduced. This method involves calculating a velocity profile for an annulus with the inner wall moving parallel to the outer wall. An average velocity is determined for the annular fluid flow, which in turn is used to calculate the fluid slippage. The results are evaluated against the historical field data and compare favorably to recent testing for smaller plunger clearances. Work remains to be done at larger clearances.

Provided that certain conditions are met, Coalbed Methane (CBM) wells have demonstrated the capacity to continue to produce a significant proportion of their peak production rates at very low reservoir pressures. Low reservoir producing pressures require low bottom-hole and surface pressures. Chief among the conditions for high production rates is being able to manage water at low surface pressure. Minimum-net-positive-suction-head considerations limit artificial-lift options. The dew point at low pressures allows large volumes of water to move as vapor - rendering mechanical separation equipment ineffective and leaving solids behind at inconvenient places. Temperature changes in buried piping condense water vapor and create both corrosion and pipe-efficiency problems. Low separator pressures preclude easy methods to remove liquid water. This paper addresses the design considerations for these low-pressure operations and related artificial lift systems Background Methane adsorbed to the surface of coal is a very old issue with some new commercial ramifications. This methane has made underground coalmines dangerous both from the risk of explosion and from the possibility of an oxygen-poor atmosphere. The miner's main concern with CBM has been how to get rid of it. With the advent of active drilling for CBM in the 1980's, the problems for CBM producers have ranged from the possible inapplicability of D'Arcy's equations to having to develop techniques to remove solids from piping and surface equipment. Coal has most of the characteristics of both source rock and cap rock [3], but few of the required characteristics of reservoir rock. Consequently, we talk about "cleat porosity" and "fracture permeability" and assign largely meaningless values to force the coal to fit our mathematical and numeric models. We talk about the flow constant in the Bureau of Mines Method of Gauging Gas Well Capacity [1] equation (i.e., q=cp (P2-PBH2)n) as being anything but constant (in the San Juan Basin of Northern New Mexico and Southern Colorado you see the cp term changing by 3% to 15% per month). The non-linearity (n) term is generally used as a fudge factor without any real physical explanation for selecting a value or for justifying changing the value. The primary offshoot of the odd behavior of CBM is that the wells retain a significant portion of their peak rates down to very low reservoir pressures. For example, one well produced 10 MMCF/d when reservoir pressure was 1,200 psia and flowing bottom-hole pressure was 125 psia - if "n" is 1.0, then cp is 0.007 MCF/(psi)2. Recently the well was making over 2 MMCF/d with 110 psia reservoir pressure and 30 psia flowing bottom-hole pressure (which would make the current cp equal to 0.179 or 25 times the peak value). The arguments around trying to describe a reason for this behavior have been much more spirited than enlightening. Most CBM fields start with low reservoir pressure, so it is important that wells in these fields see very low producing bottom-hole pressures from first production onward. There has to be a staged approach to achieving these pressures. Surface compression is used either on the gathering system or on the wellhead (or both) to pull wellhead pressures to the lowest possible values. The choice of wellbore tubulars must include minimizing the friction drop up the wellbore. A water lifting/handling strategy must be developed to keep hydrostatic head off the coalface. One strategy that has worked in several fields has been to assign the wellbore tubing to the task of water management and the tubing/casing annulus to the task of gas production. This strategy makes selection of tubing size easier and has been effective for a considerable range of individual-well production. Every CBM field produces some water. The water production ranges from over 300 bbl/MMCF in the northern end of the San Juan Basin to 2–6 bbl/MMCF in many other fields. Production and lift strategies need to be constructed around the requirements of a particular field. For high-water volume wells, many options are available. For more normal water rates, the need for lift is at least as great, but the options are significantly curtailed. A well that has inflow rates of 1 bbl/day above its evaporation-rate will collect over 20 feet of water per day in 7-inch casing - exerting almost 10 psi on the formation. A very few days of adding this kind of pressure to the formation will log a well off, but finding a lift method to move 1 bbl/day is difficult.

Liquid removal from gas wells is needed as reservoir pressure declines resulting in lower gas flow rates. As liquids accumulate in the wellbore, the hydrostatic pressure due to the liquid column exerts a backpressure on the producing sand face resulting in lower production rates. As additional liquids enter the wellbore, the well will cease to flow. By removing these liquids, gas production is maintained. Since various artificial lift techniques are used to produce these liquids, it is important that the lifting method be compatible with the size of the completions. The purpose of the paper is to discuss which options are available to lift liquids from slim-hole gas wells. Introduction The methods presented in this paper for lifting liquids from slim-hole completions deal with casings sizes ranging from 2–3/8 in. to 2–7/8 in.1 These methods for lifting liquids from these gas wells are:beam pumps,progressive cavity pumps,gas lift,hydraulic jet pumps.1,2,3 Progressive cavity pumps (PCP) may be installed within 4–1/2 in. casing with small pumps. Completion details and sizes of the various pumps and lifting systems downhole are discussed below. The production rates for beam pumping installations can range from 500 BFPD from 3000 ft to 100 BFPD from 6000 ft well with a 1–1/4 in. pump. In comparison, PCP can deliver 400 BFPD in 5–1/2 in. casing with 3–1/2 in. tubing. This rate would decline 50 BFPD for 2–3/8 in. tubing set to 5000 ft. Gas lift rates vary from 150 to 200 BFPD in 3/4 in. I. D. tubing to 900 BFPD in 1–1/2 in. I. D. tubing. Slim hole hydraulic jet pumping can produce 100 BFPD from 2500 ft with 1 in coiled tubing (CT) employed as the power fluid string, and 1–1/4 in. CT acting as the return string in 2–7/8 in. completion. Additionally, a slim hole jet pump can produce 250 to 300 BFPD with 1–1/4 in. CT inside 2–3/8 in. from 3800 ft. Using a 2–1/16 in. CT for power fluid string inside of 3–1/2 in. tubing production rates as high as 1200 BFPD from 5200 ft can be realized. These summary figures are approximate and need to be evaluated on a well-by-well basis. Slim Hole Completions with Beam Pump Beam lift is the most common method of artificial lift with a rotary motor motion converted to reciprocal motion at the surface by the surface unit. The surface unit reciprocates a string of steel sucker rods to actuate a downhole pump. Most beam pump installations use 2–3/8 in. or 2–7/8 in. tubing in 4–1/2 in. to 7 in. casing. There are many instances where it is necessary to install a beam pump into a slim hole completion for lifting fluids from liquid loaded gas wells. Casing pump & hollow rods completions For slim hole applications with beam pump, there are two possibilities. One is to simply land the pump with an insert anchore inside small casing (as small as 2–3/8's or 2–7/8's) and produce the fluid through the pump with a casing pump. The other possibility is to use a tubing insert anchore with the rubbers stripped out of the anchor and let gas bypass the pump. In this situation, gas bypasses the pump while fluid is produced from the hollow rods. Hollow rods were more common in the past; however, they are more difficult to obtain at the present time. This arrangement is shown in Fig. 1. Small tubing inside small casing Another possibility, which allows gas venting, is to use very small tubing within a 2–7/8 in. completion. A small string of rods is run inside the small tubing. Casing pump & hollow rods completions For slim hole applications with beam pump, there are two possibilities. One is to simply land the pump with an insert anchore inside small casing (as small as 2–3/8's or 2–7/8's) and produce the fluid through the pump with a casing pump. The other possibility is to use a tubing insert anchore with the rubbers stripped out of the anchor and let gas bypass the pump. In this situation, gas bypasses the pump while fluid is produced from the hollow rods. Hollow rods were more common in the past; however, they are more difficult to obtain at the present time. This arrangement is shown in Fig. 1. Small tubing inside small casing Another possibility, which allows gas venting, is to use very small tubing within a 2–7/8 in. completion. A small string of rods is run inside the small tubing.