Overview of Gas Lift; Part 3: Operational Field Procedure for Identifying, Selecting, and Optimizing a Gas Lift Well
Overview of Gas Lift; Part 3: Operational Field Procedure for Identifying, Selecting, and Optimizing a Gas Lift Well
Frank E. Ashford, Ph.D., PetroSkills Senior Advisor
John Martinez, PetroSkills Senior Advisor
Wes H. Wright, PetroSkills Senior Advisor
I. Introduction: Gas Lift Operational Fundamentals
Part 1 of this Series on Gas Lift History and Basic Well Parameters focuses on the primary “state of affairs” of Gas Lift operations in the USA. A discussion was presented related to a candidate Gas Lift well’s completion design that included a typical Casing/Tubing sizing sequence. The function of the production tubing gas lift Mandrels in starting a “kick – off” procedure in a candidate well were discussed. Types of Mandrel Gas Lift Valves were discussed, along with a discussion of the Single Gas Lift Valve (with its appropriate orifice size) employed as the final receptor of the injected casing gas.
II. Operational Fundamentals for the Performance of a Gas Lift Well, Related to Choke Flow, Single Phase Gas, and Multiphase Flowing Gradients
Part 2 of this Series reviewed energy and mass balances as related to a candidate Gas Lift Well’s flowing gradient. Energy balance equations provided the proper data to simulate both the annular flow in a casing/tubing configuration, as well as for choke (orifice) performance. Data from Industry standards provided the injected Casing/Tubing/Liner dimensions to calculate Effective Areas, as well as Effective Diameters for flow of the injected casing gas to the Production Tubing Gas Lift Valve at a given depth. The Thornhill–Craver equation provided the choke (orifice) performance data for the Gradient curves presented in Appendix A and B. The Pressure versus Gas Rate curves apply to orifice sizing but are only an estimate for gas lift valves since the valve stem in the seat reduces flow area.
Part 3 will review procedures for identifying, selecting, and optimizing technical as well as field operations for a gas lift well. Section IIIA reviews the gas lift well candidate related to gas content in the reservoir fluid and a choice of gas lift or pumping; Section IIIB discusses the well completion related to dimensional and clearance considerations and gas lift facility requirements; Section IIIC has guides for kicking off a well and avoiding erosion cutting of the unloading valves; Section IIID provides the procedure to optimize the well once it has kicked off and is operating in the production system.
Section IIIA Gas Lift Well Candidates
Reservoir conditions are primary drivers in choosing artificial lift. Gas content is key since gas lift supplements existing gas in the reservoir fluid and high content reduces the gas lift contribution. However, pumps are adversely affected by gas content in the reservoir fluid, leading to lower effectiveness and frequent failures. Production rate is a consideration that affects tubular size in gas lift, but changes pump choice with rod/beam pump for lower rates and electric submersible pump for higher rates. Finally, sand production from a sandstone reservoir or frac sand from a horizontal shale well have a detrimental effect on pump operation but a lesser effect on gas lift.
The fundamental relationship of gas lift and pumping with the reservoir is explained. Figure 1 shows a gas lift schematic on the left and the pressure‐rate behavior of flow from the reservoir (inflow) and up the tubing string (outflow) on the right. The gas lift well has gas entry through the tubing‐casing annulus to the operating valve or orifice, mixing with reservoir gas, oil, and water to reduce the composite density of the fluid, flowing to the wellhead and on to the separator. The chart at right shows the pressure versus rate for the inflow from the reservoir based on a PI = 1 bbl/d per psi and PR = 3000 psig. Each well is tested to obtain its productivity index (PI, related to IPR, Inflow Performance Relationship) and reservoir pressure (PR). This data is coupled with a nodal analysis program (PetroSkills uses SNAP from Tom Nations) to evaluate different tubing sizes and select the most appropriate. The other curves on the chart are multiphase flow results for 2 7/8” tubing outflow (called Vertical Lift Performance VLP, J‐Curve, Tubing Intake, Outflow) for natural flow and for gas lift. The intersection of the inflow curve and the outflow curve indicates a point of stable operation. The chart shows the natural flow curve (of higher density and pressure compared to gas lift) intersecting the inflow line at 400 stb/d whereas the gas lift curve (of lower density and lower bottomhole flowing pressure) intersecting at 1000 stb/d. The gas lift outflow curve is for a specific injection gas to liquid ratio (IGLR, scf/bbl) and although more injection gas would continue to decrease density, friction increase more than offsets the density reduction which is shown by the third curve in red, representing excessive IGLR that reduces production rate. IGLR plus formation gas to liquid ratio (FGLR) gives total gas to liquid ratio (TGLR). FGLR is a function of Solution Gas to Oil Ratio, Rs (scf/stb) and Oil Formation Volume Factor, Bo (bbl/stb). These two oil properties affect the quantity of “free flowing gas” which increases from the bottom of the bore to the wellhead as pressure and temperature reduce. Notice that all “outflow” curves decrease in bottomhole flowing pressure (negative slope) where density is the governing factor, and then increase (positive slope) as fluid velocity and friction become dominant.
Figure 1 – Gas Lift schematic and chart of pressure‐rate behavior (1)
Pumping is illustrated similarly to gas lift. Figure 2 shows a pump schematic on the left and on the right the pressure‐rate behavior of flow from the reservoir to the pump (inflow) and from the pump up the tubing string (outflow). A pumped well typically has no packer. Gas breaks out as reservoir fluids enter the casing and flows up the annular space to the wellhead where it is again mixed with produced fluids that are pumped up the tubing. The chart at right shows the pressure versus rate for the inflow from the reservoir based on a PI = 1 bbl/d per psi and PR = 3000 psig and represents flow into the pump suction. The other curve on the chart is multiphase outflow inside 2 7/8” tubing for natural flow and represents discharge from the pump. The chart shows the natural flow curve intersecting the inflow line at 400 stb/d, but to achieve 1000 stb/d with artificial lift, the fluid must be pumped from the intake pressure to the outflow pressure. The work energy put into the pump can be estimated from the pressure difference (Outflow pressure – Inflow Pressure), rate, and fluid density. Given more input power, a larger pump could continue to increase rate compared to gas lift, which is limited by friction.
Figure 2 – Pump schematic and chart of pressure‐rate behavior (1)
Nodal analysis simulation of gas lift and pumping is based on well testing to obtain reservoir inflow and to sample the reservoir fluids. This simulation permits evaluation of tubing sizes (and corresponding casing/liner sizes), changes in operation as reservoir conditions change, and the “best” amount of gas lift gas.
Section IIIB Gas Lift Well Dimensional and Gas Facility Considerations
Figure 3 is the gas lift well completion schematic used in Part 1 and 2. The arrangement of tubing, casing, and gas lift valves are shown, and distinction is made between unloading (kick off) valves and a bottom orifice for continuous injection.
Figure 3 – Gas lift well schematic and surface facility (2)
Prior to drilling, a tubing/casing size evaluation is conducted using exploration or prior well data as estimates for PI and reservoir pressure. If the reservoir has the rate capacity and engineering concurs that higher rates will not damage the reservoir rock nor preclude reserves recovery, then a larger size tubing and corresponding casing can be recommended. Once tubing/casing sizes are selected, a detailed dimensional analysis is required. The gas lift mandrels and associated valves are eccentric (both conventional tubing retrievable and side pocket with wireline retrievable valves) and clearance between the casing and tubing must be assured. The inside drift diameter of casing must be compared to tubing coupling outside diameter and to gas lift mandrel major diameter. Table 1 has tubing, casing, and gas lift mandrel dimensional data for a clearance check. The 9 5/8” casing string from Figure 3 has a drift diameter of 8.525”, much larger than the major outside diameter (OD) of a 2 7/8” gas lift mandrel (9 5/8” casing is usually paired with 3 1/2” or 4 ½” gas lift completions). The 7” liner has a drift diameter of 5.969” which will clear the 2 7/8” gas lift mandrel major OD of 5.5” for a side pocket or 4.835” for a tubing retrievable option. Downhole data confirms clearance, so attention can be turned to surface facilities.
Table 1: Production Tubing, Casing, and Valve Mandrel Dimensions for Clearance [3,4,5]
Gas compressors, dehydrators, and meters are the crucial complements to the wellbore, subsurface valves, and low pressure gathering/treating facilities of the gas lift system, Figure 4. All operations staff will tell you that gas lift success depends on near 100% run time from compressors, dehydrators, and gas lift gas meters. The rate and pressure available to each well must be adequate and steady. If compressors go down every few days due to poor maintenance or old equipment, then the gas lift system cannot stabilize. Wells are always in a startup (kick off) mode, not steady state operation. If dehydration is malfunctioning or the triethylene glycol (TEG) is so fouled that it cannot absorb water vapor from the gas stream, then hydrate at chokes, regulators, distribution piping, or fuel gas supply lines will cause individual wells, or portions of the field, or the entire field to go offline. Liquid accumulation over years due to condensing water vapor in the piping system can lead to corrosion, liquid slugging, and loss of gas transmission efficiency. Since most gas lift gas is dehydrated but unprocessed solution gas plus returning lift gas, it usually contains heavy hydrocarbon components which can condense and accumulate in the piping system causing problems.
Figure 4 – Gas lift field schematic with well and surface facility (6)
The critical quality of gas lift gas centers on water content in the gas at compressor discharge pressure and temperature. The value can be estimated from Figure 5. At compressor discharge downstream of the aftercooler, the pressure is 1400 psig and temperature is 120⁰F. The water content point on the chart is 80 lbs water vapor per million standard cubic feet (MMscf) gas. To prevent water condensation down to 40⁰F at 1400 psig, the water content must be reduced to 7 lbs water per MMscf and the TEG dehydrator must remove 73 lb/MMscf. Colder climes often require 1 lb/MMscf to achieve a dew point of ‐10⁰F, which requires 79 lb/MMscf water vapor removal. These estimates set the dehydration requirement to prevent water condensation in the piping which leads to hydrate, corrosion, and water accumulation.
When the dehydrator is out of service for an extended period, or if dehydration is not installed under the false assumption of no problem with hydrate, corrosion, or water accumulation in the injected gas piping system, then a chart is used to predict hydrate formation pressure and temperature based on the gas lift gas specific gravity (ranges from 0.65 to 0.8). Gas lift gas (0.7 specific gravity or relative density) at our example 1400 psig discharge pressure could form a hydrate at approximately 68⁰F, which during normal operation, could occur at pressure expansion (and cooling) locations at chokes, regulator valves, and piping low points where water accumulates. As weather cools many points, including the main pipeline or laterals, could be subject to hydrates. Methanol or ethylene glycol injection stations would be required at potential hydrate points to keep the gas lift operating.
Figure 5 – Water content of hydrocarbon gas (7)
Figure 6 – Pressure‐temperature curves for predicting hydrate formation (7)
Section IIIC Gas Lift Well Unloading (Kick off) Guide
An important first step is extracting the control (kill) fluid that is used by the completion/workover team to permit safe installation of the downhole equipment. Even though blowout preventers (BOP) are used, control (kill) fluid in the wellbore tubing and tubing‐casing annulus is the primary barrier to prevent reservoir fluid flow. With the well full of control (kill) fluid, the BOP is removed and replaced with the tree of valves and flanges are sealed. Now thevcritical unloading (kicking off) of the well can be slowly initiated to prevent erosion of valves/mandrels as thevcontrol (kill) fluid passes from the annulus to the tubing, where it flows up to the wellhead to be removed from the well.
Damage prevention to valves and mandrels requires actions prior to installing the downhole equipment and after tree installation. The following practices are applied during the workover to install the packer, tubing, mandrels, and valves:
a) Circulate the wellbore to remove any drilling mud before perforating, running other completion equipment, and installing the gas lift valves.
b) Use a casing scraper to remove debris that adheres to the casing wall and burrs created when packers were set; circulate the casing clean.
c) Use filtered completion and workover fluids and leave filtered fluid in the tubing‐casing annulus. Unfiltered fluids are often a source of solids that can either cut out or plug the gas lift valves.
Unloading the control (kill) fluid from the tubing and annulus is initiated after the well is secured to the production facility:
a) Displace with unloading rates not exceeding 1 barrel per minute (BPM) to prevent erosion of gas lift valves.
b) Start injection gas flow, control rate to attain a 50 psig casing pressure increase in 10 minute increments.
c) Continue this injection rate until the casing pressure reaches 400 psig.
d) Increase the injection gas rate to achieve a 100 psig increase in 10 minute increments.
e) Monitor for an injection gas pressure drop and the return of aerated fluid from the production tubing to indicate gas is injected through the top unloading valve.
f) Observe and record casing pressure (downstream of injection choke or regulator valve) to confirm casing pressure decline as injection point transfers to deeper valves.
g) Use acoustic fluid level tools in the casing annulus to confirm depth of injection.
h) Ensure that injection gas flow is continuous and avoids the occurrence of CRITICAL FLOW where the ratio (P2/P1) of the downstream choke pressure, P2, and the upstream pressure, P1, are in a range well above 0.60., i.e. 0.85 – 0.65.
The depth of injection is related to reservoir pressure (and corresponding tubing pressure) compared to the casing injection pressure. Early operating life may have gas lift injection at a mid‐point in the wellbore, but as reservoir pressure and tubing pressure decline with time, the injection point will automatically shift to a deeper valve where gas injection pressure is greater than tubing pressure. Testing after unloading coupled with nodal analysis simulation from each valve mandrel depth can indicate the point of operation, illustrated in Figure 7. This figure shows the well unloaded to the deep mandrel at 8000’ (Test 1), but a compressor outage caused a shift to the shallow mandrel at 4800’ (Test 2) (the well may not automatically return to the deep point of injection after the restart). Operators adjusted injection rate and another test indicated lift at the 7150’ mandrel (Test 3), and a subsequent test showed a return to the mandrel at 8000’ (Test 4). When the well is unloaded to the depth possible based on available injection pressure, and confirmed with acoustic fluid level and testing, then optimization testing can begin.
Figure 7 – Production rate versus mandrel depth (1)
Section IIID Gas Lift Well Optimization
Optimization based on well tests is an ongoing process since the reservoir inflow performance is continually changing and injection gas needs to be allocated to the best wells in a group supported by the same compressor station. However, confirmation of deep lift (related to available injection pressure) should be done first based on the prior section. The well tests, flowing gradient surveys, and measured flowing bottomhole pressure data from permanent sensors are used to build nodal analysis models that accurately describe the wells’ response to greater or lesser amounts of injection gas. The well performance curve, previously shown in Figure 7, is also called an “optimization” curve and charts gross production (oil and water) rate versus injection gas rate. Each well in the field is tested over a range of 80% to 120% of design injection rate; the results permit choice of operating point based on some criteria: maximum oil, best economic condition, flow stability to minimize slugging, water injection capacity, injection gas capacity. The group of wells in same facility can have injected gas allocated to achieve the “optimum” operating point for each well. Often, optimization is not attained.
When wells falter and optimum points cannot be achieved, troubleshooting techniques are applied to obtain data for problem resolution. Diagnostic techniques, solutions, and problems are addressed in the following table:
Section III Summary
This gas lift tip of the month (TOTM) provides information on gas lift well selection and its inflow relationship with the reservoir, on wellbore and facility parameters that must be addressed for operational success, on the critical stage of unloading control (kill) fluid that is in the wellbore following all interventions to install downhole equipment, and on the optimization procedure plus trouble shooting guides.
Section IIIA links gas lift choice to reservoir gas content since high available reservoir gas requires a lower supplement from gas lift. The effect is density reduction in the wellbore and nodal analysis graphs are used to indicate the difference between a lower natural flow rate and a higher gas lift rate that results from the lower pressure in the bottom of the bore. Nodal analysis with SNAP is used to evaluate interdependence of reservoir productivity, tubing size (with corresponding casing size), and gas lift injection pressure availability.
Section IIIB has an example that compares tubing, gas lift mandrel eccentricity, and casing drift diameters to assure the equipment can installed in the wellbore. Downhole evaluation is necessary, as is a review of surface facilities. Success with gas lift depends on high reliability compressors and dehydrators that provide steady gas capacity without hydrates or liquid accumulation.
Section IIIC provides guides to the crucial step of removing the control (kill) fluid without causing erosional cutting of valves/mandrels. Damage control involves actions prior to installing the wellbore hardware and precautions during the fluid extraction procedure. Displacement of control (kill) fluid is limited to 1 barrel per minute, deemed by testing to be the maximum rate where erosion will not occur.
Section IIID provides the multirate well test optimization procedure to obtain gross production rate versus injection gas rate varied over a range of 80% to 120% of design rate. This test phase begins after the well is confirmed to be lifting at a depth consistent with the available injection pressure. An “optimum” operating point is selected based on criteria such as maximum rate, or economic return, or flow stability, or capacity limits of
injection gas or injection water. When testing reveals a problem, then trouble shooting analysis begins using the guides in this section.
The Authors acknowledge and express our gratitude to Kindra Snow‐McGregor and to Mahmood Moshfeghian for their valuable review and feedback.
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Edition, 3rd Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, PetroSkills 2018