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The primary surface equipment for a sucker-rod lift system is the pumping unit and its prime mover. But a variety of other equipment is also used in the surface operations for this type of artificial lift. This page discusses the polished rod, associated clamps, stuffing boxes, rod rotators, pumping tees, check valves, and surface valves. A polished rod is the top-most rod in a rod string. These rods come in various lengths and sizes.
Introduction Tubing is the normal flow conduit used to transport produced fluids to the surface or fluids to the formation. Its use in wells is normally considered a good operating practice. The use of tubing permits better well control because circulating fluids can kill the well; thus, workovers are simplified and their results enhanced. Flow efficiency typically is improved with the use of tubing. Furthermore, tubing is required for most artificial lift installations. Tubing with the use of a packer allows isolation of the casing from well fluids and deters corrosion damage of the casing. Multicompletions require tubing to permit individual zone production and operation. Governmental rules and regulations often require tubing in every well. Permission may be obtained for omission of tubing in special cases (tubingless completions). These special completions typically are flowing wells with relatively small casing. Tubing strings are generally in outside diameter (OD) sizes of 2 3/8 to 4 1/2 in. The proper selection, design, and installation of tubing string are critical parts of any well completion. See the chapter on inflow and outflow in this section of the handbook for more information. Tubing strings must be sized correctly to enable the fluids to flow efficiently or to permit installation of effective artificial lift equipment. A tubing string that is too small causes large friction losses and limits production. It also may severely restrict the type and size of artificial lift equipment. A tubing string that is too large may cause heading and unstable flow, which results in loading up of the well and can complicate workovers. The planned tubing must easily fit inside the installed casing.
This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.
Many oilfield processes normally employed on the surface may be adapted to downhole conditions. Examples include phase separation, pumping, and compression. Sometimes the design specifications for downhole processes may be looser than surface processing because control is more difficult. Partial processing, in which fluids are separated into a relatively pure phase stream and a residual mixed-phase stream, are most common. Downhole separation technology is best suited for removing the bulk (50 to 90%) of the gas or water, with downstream surface or subsea equipment being used to "polish" the streams for complete separation.
Sand and other solids production can cause problems in PCP systems by accelerating equipment wear, increasing rod torque and power demand, or causing a flow restriction by accumulating around the pump intake, within the pump cavities, or above the pump in the tubing. Also, given its specific gravity of 2.7, even moderate volumes of sand can substantially increase the pressure gradient of the fluid column in the production tubing. Sand production is frequently a byproduct of oil production, especially in some primary heavy oil operations (e.g., Canada) where it is an important part of the recovery process. In such operations, sand influx is usually most severe during the initial stage of production when the volumetric sand cuts can exceed 40%. Subsequently, the sand cuts often stabilize at 3%.
Wells producing water are likely to develop deposits of inorganic scales. Scales can and do coat perforations, casing, production tubulars, valves, pumps, and downhole completion equipment, such as safety equipment and gas lift mandrels. If allowed to proceed, this scaling will limit production, eventually requiring abandonment of the well. Technology is available for removing scale from tubing, flowline, valving, and surface equipment, restoring at least some of the lost production level. Technology also exists for preventing the occurrence or reoccurrence of the scale, at least on a temporary basis. "Temporary" is generally 3 to 12 months per treatment with conventional inhibitor "squeeze" technology, increasing to 24 or 48 months with combined fracture/inhibition methods. As brine, oil, and/or gas proceed from the formation to the surface, pressure and temperature change and certain dissolved salts can precipitate. If a brine is injected into the formation to maintain pressure and sweep the oil to the producing wells, there will eventually be a commingling with the formation water. Many of these scaling processes can and do occur simultaneously. Scales tend to be mixtures.
Electrical submersible pumps focuses on the standard ESP configuration. It has the pump, seal chamber section, and motor attached to the production tubing, in this order from top down. In some wellbore completions and unique ESP applications, the arrangement and configuration of the system is modified. For a bottom-intake design, the production fluid is drawn in the intake ports located at the very bottom of the ESP system and discharged out of ports located just below the connection to the seal-chamber section. Because the discharged production fluid cannot flow through the seal-chamber section and motor, it has to exit into the casing or liner annulus and flow past these units.
Obeid, Ahmad Fayyad (Adnoc Offshore) | Bespalov, Eugene (Schlumberger) | Sanghavi, Dharam (Schlumberger) | Almasri, Ahmad (Schlumberger) | Magri, Jose (Schlumberger) | Al Hammadi, Majid Ismail (Adnoc Offshore) | Al Marzooqi, A. M. (Adnoc Offshore) | Yoshimoto, Kazuhito Kazumi (Adnoc Offshore) | Yamashita, Hajime (Adnoc Offshore) | Al Zaabi, Ali Yousef (Adnoc Offshore)
Abstract Electric submersible pumps (ESPs) used as an artificial lift method have a relatively short life span despite the industry's efforts to improve reliability. The resulting economic impact realized in workover costs and production loss is substantial. This has driven efforts toward design change by introducing retrievable ESP independent of the completion string and hence extending ESP wells’ life cycle. This paper covers the company's first installation of a rigless shuttle ESP system, including a customized completion design and special deployment procedures. A comprehensive approach was taken to deploy this technology, from procurement to installation, in a detailed process. It started with acquiring reservoir data and setting up matching specifications for the required equipment in order to issue a competitive tender. Following technical evaluation of tender submissions, the most suitable technology was selected for the field trial. The completion design was then customized to accommodate the new technology without jeopardizing well integrity. Fit-for-purpose well barriers were incorporated in the completion design because conventional barriers were not applicable. Detailed running procedures were produced from dedicated workshops and risk assessment reviews. Project execution was closely monitored and firmly controlled. The company has accomplished the first successful offshore deployment of the shuttle ESP system in the MENA region. The system was deployed using tailored procedures for installation and comprehensive testing while ensuring compliance with well barrier requirements. Following successful deployment, the ESP performance was positively tested. Part of the project validation requirement was a rigless retrieval and redeployment the ESP system. The ESP retrieval process was challenging due to unexpected tar or asphaltene material encountered above the ESP. However, contingency retrieval procedures were promptly amended with detailed steps to overcome this challenge, which led to successful retrieval and redeployment of the ESP without NPT. This success is paving the way for a major change in the company's field development strategies by considering rigless, replaceable ESP systems instead of the conventional ESPs. This paper sheds the light on a new advancement in completion technology that has a strong potential to prevail for ESP-lifted wells in the future. The focus of the paper is on the design and execution parts, as well as installation and post-completion operations while maintaining sufficient well barriers―the challenging aspect that appears to be slowing down the wider use of this technology as a replacement of conventional ESP completions.
Abstract Growth in the coal seam gas industry in Queensland, Australia, has been rapid over the past fifteen years, with greater than USD 70 billion invested in three liquified natural gas export projects supplied by produced coal seam gas. Annual production is of the order of 40 Bscm or 1,500 PJ, with approximately 80% of this coming from the Jurassic Walloon Coal Measures of the Surat Basin and 20% from Permian coal measures of the Bowen Basin. The Walloon Coal Measures are characterized by multiple thin coal seams making up approximately 10% of the total thickness of the unit. A typical well intersects 10 to 20 m of net coal over a 200 to 300 m interval, interbedded with lithic-rich sandstones, siltstones, and carbonaceous mudstones. The presence of such a significant section of lithic interburden within the primary production section has led to a somewhat unusual completion strategy. To maximize connection to the gas-bearing coals, uncemented slotted liners are used; however, this leaves fluid-sensitive interburden exposed to drilling, completion, and produced formation fluids over the life of a well. External swellable packers and blank joints are therefore used to isolate larger intervals of interburden and hence minimize fines production. Despite these efforts, significant fines production still occurs, which leads to failure of artificial lift systems and the need for expensive workovers or lost wells. Fines production has major economic implications, with anecdotal reports suggesting up to 40% of progressive cavity pump artificial lift systems in Walloon Coal Measures producers may be down at any one time. The first step in solving this problem is to identify the extent and distribution of fines production. The wellbore completion strategy above, however, precludes use of mechanical calipers to identify fines production-related wellbore enlargement. A new caliper-behind-liner technique has therefore been developed using a multiple-detector density tool. Data from the shorter spacing detectors is used to characterize the properties of the liner as well as the density of the annular material. This is particularly important to evaluate as the annulus fill varies between gas, formation water, drilling and completion fluids, and accumulated fines. The longer spacing detector measurements are then used in conjunction with pre-existing open-hole formation density measurement to determine the thickness of the annulus, and hence hole size, compensating for liner and annulus properties. This methodology has been applied to several wells completed in the Walloon Coal Measures. Results have demonstrated the ability to identify zones of borehole enlargement behind slotted liner, as well as intervals of either gas or fines accumulation in the annulus. In addition, the technique has been successful in verifying the placement of swellable packers and their integrity. The application of this solution has been used to drive improvements in the design of in-wellbore completion programs and in the future will help drive recompletion decisions and trigger proactive workovers.
Romer, Michael Christopher (ExxonMobil Upstream Research Company) | Spiecker, Matt (ExxonMobil Upstream Research Company) | Hall, Tim James (ExxonMobil Upstream Research Company) | Dieudonne, Raphaël (Hydro Leduc) | Porel, François (Hydro Leduc) | Jerzak, Laurent (Hydro Leduc) | Ortiz, Santos Daniel (KSWC Engineering & Machining) | King, George Randall (KSWC Engineering & Machining) | Gohil, Kartikkumar Jaysingbhai (KSWC Engineering & Machining) | Tapie, William (Deteq Services) | Peters, Michael (MTI) | Curkan, Brandon Alexander (C-FER Technologies)
Summary What do you do after plunger lifting? What if lift gas is not readily available or your liquid level is around a bend? What can you do with a well that has low reservoir pressure, liquid-loading trouble, and fragile economics? Do you give up on the remaining reserves and advance to plugging and abandonment? These questions were considered, and the answers were found to be unsatisfactory. This paper will describe the development and testing of a novel wireline-deployed positive-displacement pump (WLPDP) that was invented to address these challenges. Artificial-lift (AL) pumps have historically been developed with high-producing oil wells in mind. Pumps for late-life wells have mostly been repurposed from these applications and optimized for reduced liquids production. The WLPDP development began with the constraints of late-life wells with the goal of addressing reserves that conventional AL methods would struggle to produce profitably. Internal and industry-wide data were first reviewed to determine what WLPDP specifications would address the majority of late-life wells. The primary target was gas wells, although “stripper” oil wells were also considered. The resulting goal was a pump that could deliver 30 BFPD from 10,000-ft true vertical depth (TVD). The pumping system must be cost-effective to be a viable solution, which led to several design boundaries. Pumps fail and replacement costs can drive economics, so the system must be deployable/retrievable through tubing. The majority of new onshore wells have tortuous geometries, so the system must be able to function at the desired depth despite them—without damaging associated downhole components. The system should use as many off-the-shelf components and known technologies as possible to reduce development costs and encourage integration. Finally, the pump should be able to handle a variety of wellbore liquids, produced gases, and limited solids. The WLPDP was designed to meet the established specifications and boundary conditions. The 2.25-in.-outer-diameter (OD) pump is deployed through tubing. and powered with a standard wireline (WL) logging cable. The cable powers a direct-current (DC) motor that drives an axial piston pump. The piston pump circulates a dielectric oil between two bladders by means of a switching valve. When each bladder expands, it pressurizes inlet-wellbore liquids, pushing them out of the well. Produced gas flows in the annulus between the tubing and production casing. The intake/discharge check valves and bladders are the only internal pump components that contact the wellbore fluids. The WLPDP system was able to meet the design-volume/pressure specifications in all orientations, as confirmed through laboratory and integration testing. Targeted studies were conducted to verify/improve check-valve reliability, gas handling, elastomer suitability, and cable-corrosion resistance. The results of these and related studies will be discussed in the paper.