Completion Techniques and equipment

.pdf

School

Tulsa Community College *

*We aren’t endorsed by this school

Course

2034

Subject

English

Date

Oct 30, 2023

Type

pdf

Pages

Uploaded by CountMulePerson720

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 1/70 PE 4063 / 6463 – Well Completion GROUP – 1 Introduction to Well Completions SET 2 – Types of Completions & Equipment Introduction The purpose of drilling is to explore, to produce hydrocarbons from, or to inject fluids into, hydrocarbon-bearing formations beneath the earth's surface. The borehole provides a conduit for the flow of fluids either to or from the surface. Certain equipment must be placed in the wellbore, and various other items and procedures must also be used to sustain or control the fluid flow. This equipment and any procedures or items necessary to install it are collectively referred to as well completion. Well completion can be conducted in various types depending on the reservoir properties, drive mechanisms, fluid properties, company strategies and objective, etc. but, in general, as the well completion process is concerned, generally two different designs are required; i) bottomhole design, and ii) surface design. Some of the methods of completion schemes are presented below. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 2/70 In the early twentieth century, oil and gas wells were commonly completed with only a single string of casing. The casing was a large diameter (e.g. 7-in.) string of steel pipe, consisting of threaded sections. Initially, casing was set with drilling fluid only. A casing string in a well extends from the surface to some setting depth. If the top of a casing string is set at a depth below the surface, it is referred to as a liner. Liners are commonly found in wells completed during the early part of the twentieth century. Cementing technology evolved in the 1920s, and by the 1930s, most casing strings were set with some cement. Cementing a well is an essential step in almost all well completions, irrespective of whether a perfect bond is achieved between the reservoir and the casing. Currently, most wells are cemented at least some distance above the target reservoir. In early completions, casing was either set at the top of the producing zone as an openhole completion or set through the producing reservoir. Openhole completions minimize expenses and allow for flexible treatment options if the well is deepened later, but such completions limit the control of well fluids. Openhole completions can also reduce sand and water production. Although many wells completed in this manner are still operating today, this method of completion has been superseded by cased completions.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 3/70 In a cased completion, casing is set through the producing reservoir and cemented in place. Fluid flow is established by the creation of holes or perforations that extend beyond the casing and cement sheath, thereby connecting and opening the reservoir to the wellbore. Wells that are cased through the producing reservoir provide greater control of reservoir fluids because some or all of the perforations can be cemented off or downhole devices can be used to shut off bottom perforations. However, openhole wireline logs must be run before the casing is set so that the exact perforation interval is known. Cased- hole completions are more susceptible to formation damage than openhole completions. Formation damage refers to a loss in reservoir productivity, normally associated with fluid invasion, fines migration, precipitates, or the formation of emulsions in the reservoir. These early completion techniques proved adequate in relatively shallow wells. However, as deeper, multiple, and higher-pressure reservoirs were encountered, it was recognized that the completions imposed limitations on well servicing and control and designs would require improvement to meet increasing requirements for wellbore re-entry and workover operations. A wide range of downhole equipment has been designed and manufactured to meet the needs of more complex well completions. In situations where multiple reservoirs cannot be commingled, the zones are separated with TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 4/70 a production packer. Packers are devices that are run on, or in conjunction with, a string of tubing. The packer has a rubber element that is extruded by compression to form a seal between the tubing and the casing. Packers are used for a variety of reasons in well completions. Another component that has become an integral part of well completions is the sliding sleeve. The sliding sleeve provides annular access between the tubing and the casing. It is used to produce a reservoir isolated between two production packers and for circulating a well above the uppermost packer. The sleeve is opened or closed through the use of wireline servicing methods. Many other functions can be performed with wireline devices set in landing nipples. Engineers designing well completions must consider that the wells will eventually be unable to flow naturally to the surface. The loss of natural flow occurs because the reservoir pressure declines with production and reservoirs produce increasing amounts of water with time, which increases the density of the flowing fluid. Various techniques of artificially lifting fluids from the wellbore have been developed. Artificial lift techniques include sucker rod pumping, electrical submersible pumps, gas lift, and other types of hydraulic lift. Each method of artificial lift requires unique downhole and surface equipment that must be considered during the design of the well completion. Well

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 5/70 stimulation techniques introduced in the early part of the twentieth century have been improved through a more complete understanding of the processes involved. Acidizing models have been developed to describe the use of various types of acids in a range of lithologies. Hydraulic fracturing has experienced even more dramatic improvements since the introduction of crosslinked polymer fluids, high-strength proppants, and analytical techniques, such as the net pressure plot. Such techniques have enabled engineers to substantially improve the flow from both low-permeability and high- permeability reservoirs. Another notable advance in well completion design is the evolution of coiled tubing for servicing and completing wells. Coiled tubing servicing involves the deployment of a continuous string of small-diameter tubing into the wellbore. This coiled tubing is run concentric to existing tubulars, is used for the required service, and is then removed without damaging the existing completion. Coiled tubing servicing is of increasing importance in highly deviated and horizontal wells, since wireline servicing poses problems at angles greater than 50  . Completion methods such as gravel-packing and stimulation, a variety of downhole equipment, and enhancements to servicing methods have enabled engineers to design more TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 6/70 complex well completions, which offer greater fluid flow control, stimulation alternatives, and operational flexibility. An extensive range of downhole designs has been implemented to meet a number of producing requirements. Example designs include dual completions, slimhole and monobore completions, completions for high-pressure, high temperature (HPHT) reservoirs, subsea completions whose wellheads are located on the seafloor, and waterflood or CO 2 injection applications. Two examples, a dual completion and a subsea completion with gravel-packing and artificial lift, illustrate the wide range of well completion designs available today. Dual completions are used when multiple reservoirs will be produced. Two tubing strings and at least two production packers are included. The packers may separate two or more producing reservoirs. A sliding sleeve can be included between or above packers so that one or more reservoirs can be selectively produced at any time. Other downhole equipment, such as landing nipples, safety valves, or side-pocket mandrels (for gas lift) may be included in a dual completion. At present, most horizontal wells are either completed with an openhole horizontal section, with a slotted liner laid in the openhole section, or with a gravel-pack screen. To date, the use of casing, production packers, sleeves, and other downhole devices has been limited because they cannot provide a

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 7/70 mechanical/hydraulic seal at the junction between the vertical wellbore and the horizontal hole. Completion technology in this area is evolving rapidly, and such capabilities will likely be available in the near future, enabling the use of downhole devices and techniques that will provide greater control of fluid flow and stimulation in horizontal and multilateral wells. An oil or gas well completion should fulfill the technical requirements for the various phases which exist throughout the life of the well or reservoir, e.g., initial production, treatment/stimulation, artificial lift, workover and abandonment. However, in order to fulfill basic safety and economic requirements of any installation some compromise may be necessary. As the performance of wells, and therefore completions, have become more closely scrutinized, the basic design and component selection process has evolved. Selection of Flow Conduit Between Reservoir & Surface for a Single Producing Formation There are a number of optional methods by which fluid which enters the wellbore will be allowed to flow to surface in a production well, or to the formation in an injection well. In the selection of the method, a range of considerations may influence the choice including: cost, flow stability, ability to control flow and ensure well safety or isolation; ensuring that the integrity of the well will not be compromised by corrosion TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 8/70 or erosion. In the case of multizone reservoir, the zonal characteristics will determine to a large extent the flow system selected. However, for a single zone completion, the following alternatives exist:  Tubingless casing flow.  Casing and tubing flow.  Tubing flow without annular isolation.  Tubing flow with annular isolation. Tubingless Casing Flow In this option, once the well has been drilled and the bottom hole completion technique implemented, i.e., open hole or perforated casing, the well is induced to flow under drawdown and fluid is produced up the inside of the casing. This technique is very simple and minimizes costs. However it is not without its disadvantages. Firstly, the production casing may be of such a diameter that the flow area is so large that the fluid superficial velocities are low enough for phase separation and slippage to occur, resulting in unstable flow and increased flowing pressure loss in the casing. To be effective, this approach is only applicable for high rate wells. Secondly, the fluid is in direct contact with the casing and this could result in any of the following:  Casing corrosion, if H 2 S or CO 2 are present in produced fluids.  Casing erosion, if sand is being produced.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 9/70  Potential burst on the casing at the wellhead if the well changed from oil to gas production. When a well is required to be worked over, the first requirement is that the well be hydraulically killed. In this type of completion, the reinstatement of a hydraulic head of fluid which provides a bottom hole pressure greater than reservoir pressure can only be accomplished by either “squeezing” the wellbore contents back into the formation, or circulating across the wellhead using the “Volumetric Technique”. For the majority of wells, either the productivity does not merit the use of such large annular diameters or the difficulties in well killing are significant and hence the application of this type of completion is limited to areas of very high well productivities. However it can be a fairly reliable completion with a long life and minimal major workover requirements in view of its very basic design, provided that it does not suffer from abrasion or corrosion of the production casing. Casing and Tubing For highly productive wells where a large cross sectional area for flow is desirable, an alternative to the tubingless casing flow would be to install a production tubing and allow flow to occur up the tubing and the tubing- casing annulus. This type of completion has the very important advantage of providing a TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 10/70 circulation capability deep in the well where reservoir fluids can be displaced to surface by an injected kill fluid of the required density to provide hydraulic overbalance on the reservoir. This capability to U-tube fluid between the annulus and the tubing removes the necessity for re-injection into the reservoir and would not require the high pressures associated with squeeze operations. Provided no erosive or corrosive compounds exist in the flow stream, this completion is very useful for high flow rate wells. Tubing Flow Without Annulus Isolation In situations where annular flow in a casing-string completion would result in excessive phase slippage with consequent increased flowing pressure loss and potential instability, the consideration could be given to merely closing the annulus at surface and preventing flow. However, in reservoirs where the flowing bottom hole pressure is at or below the bubble point, gas as it flows from the formation to the tubing tailpipe will migrate upwards under buoyancy forces and some gas will accumulate in the annulus. This will result in an increase in the casing head pressure at surface. Gas build up in the annulus will continue until the gas fills the annulus and it will offload as a gas slug into the base of the tubing and be produced. This production instability will be cyclical and is referred to as annulus heading. In this type of completion the casing is exposed continuously to produced fluid with the possibilities of

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 11/70 erosion or corrosion. This, coupled with the potential for annular heading, suggests that unless annular flow is required then the annulus should not be left open to production, despite its simple design. Tubing Flow With Annulus Isolation For cases where a large cross sectional area for flow is not necessary, then an open annulus can cause complications. Therefore, in the majority of cases where tubing flow will take place, the annulus is normally isolated by the installation of a packer. The packer has a rubber element which when compressed or inflated will expand to fill the annulus between the tubing and the casing. The packer is normally located as close to the top of the reservoir as possible to minimize the trapped annular volume beneath the packer and hence the volume of gas which could accumulate there. However, if the packer is installed, the ability to U-tube or circulate fluid between the tubing and annulus is removed. If such a circulation capability is required then it is necessary to install a tubing component which will allow annulus communication or alternatively rely upon the ability to perforate the tubing which consequently would necessitate tubing replacement prior to the recommencement of production. In both cases, the circulation point is normally as deep in the well as possible, but above the packer. This completion system is by far the most widely used and offers maximum well security and control. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 12/70 Advanced Systems Exploration and production of oil and gas have been transformed over the past ten years by extensive developments in well systems and technology. Drilling and completion technology has made possible new well shapes that have increased the efficiency of oil production. The definition of advanced wells encompasses a range of new technologies that may be applied individually or in combination:  Horizontal wells  Extended or ultra-reach wells  Multi-lateral wells  Intelligent (“smart”) wells  Coiled tubing drilling/reeled completions  Underbalanced operations  Multiply fractured horizontal wells Such wells are also known as “unconventional” wells or, in the case of complex trajectories, the term “designer” well is sometimes used. The motivation for using this technology is to:  Access otherwise inaccessible reserves  Improve recovery factor/sweep efficiency  Increase flow rates  Enhance profitability per dollar invested

Your preview ends here

Eager to read complete document? Join bartleby learn and gain access to the full version