Completion Techniques and equipment

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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

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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

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 13/70 Advanced wells are characterized by more demanding application of established methods in production geoscience and petroleum engineering:  The well configuration is more complex requiring an accurate reservoir description with adequate data  Costs have to be well understood and a robust economic analysis must be carried out  The full life cycle with possible recompletions, workovers and stimulation must be considered in advance  A thorough assessment of risks with consequent contingency planning is essential Advanced wells can bring commercial benefits and allow cost effective data acquisition to be carried out. The commercial benefits occur through one or more of the following:  Reduced capital expenditure per barrel  Reduced operating expenditure per barrel  Accelerated reserve steam The data acquisition occurs through probing of the lateral limits of the reservoir using logging while drilling. Difficulties and challenges that arise in advanced well applications are:  In conjunction with improved benefits, the potential risks are greater TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 14/70  Increased complexity requires more rigorous validation and design  Operational constraints are greater  Concentration on fewer wells in the development increases detrimental impact of losing one well The time frame begins twenty years ago when horizontal wells became a reliable option in field development. At the same time the limits reachable by extended reach wells were being extended. Some business drivers that have boosted advanced well technology are:  Low oil prices  Competitive need for cost reduction

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 15/70  Accelerated production and cash flow  Increasing recovery using existing infrastructure Many advanced well types were prototyped in the Soviet Union as early as the 1950s. They were then brought to commerciality in North America and elsewhere in the 1980s. To get the maximum benefit from advanced well technology we need a rigorous planning process that brings together the appropriate level of knowledge and experience and enjoys the full support of senior management. A good database containing reservoir and well details in the area around the proposed well is the foundation of this planning process. The plan should not only focus on drilling, completion and early production but should cover the full life cycle of the well through to abandonment and should address all reasonable contingencies in this period. The design principles should be simple and clear to all participants and practical to implement. Horizontal Wells Long lateral sections horizontal or parallel to bedding plane. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 16/70 Extended Reach Wells Drilling technology now allows lateral research to be more than 10 times the vertical depth of the reservoir for moderate depth reservoirs. Although drillable, there are completion and intervention problems to be overcome. Generally the $/barrel cost will be higher than for a conventional, shorter reach 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, 17/70 Multi-lateral Wells Wells with two or more branches joined to a main or mother well bore. An example of a dual-opposed configuration. Intelligent (“Smart”) Wells Smart wells are horizontal wells that have downhole instrumentation that can not only measure downhole parameters such as flow rate, fluid composition and pressure, but they can also have downhole flow control devices that can regulate and optimize the flow of hydrocarbons to surface. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 18/70 Coiled Tubing Drilling Coiled tubing drilling uses continuous pipe spooled onto a reel. The drill-bit, powered by a downhole mud motor can often be run through an existing completion, which avoids the cost of a full workover. The horizontal section that can be achieved is currently of smaller diameter and shorter than wells drilled with conventional equipment.

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 19/70 Underbalanced Drilling Use of lighter mud can lead to the bottom hole pressure being less than formation pressure. Such underbalanced conditions can be safe provided adequate pressure control and fluid handling facilities are available at surface. The advantages are reduced formation damage and increased rate of penetration. Although underbalanced drilling can be carried out using conventional drill pipe with a drilling rig it is quite common nowadays to combine coiled tubing drilling with underbalanced drilling. Multiple Fractured Horizontal Wells In a low permeability formation where vertical wells are usually fractured it may be necessary to also hydraulically fracture horizontal wells. The orientation of the fracture depends on the principal stress direction. If the well has been drilled approximately along the principal stress direction then the fracture will be along this direction. If the well direction is approximately perpendicular to the principal stress direction then the fracture planes will be perpendicular to the well direction and many fractures will be required to get good drainage volume in the reservoir. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 20/70 Horizontal Well Basics In this section, we introduce the basics of drilling and completing a horizontal well. We discuss well trajectory and geo-steering and examine reservoir flow regimes and drainage areas. In general, this concerns high rate wells (>1000 b/d, or 160 m 3 /d) drilled in deep reservoirs (>2000 m TVD below surface), i.e., rates which are required offshore to be commercial. Usually such wells use medium or long radius build section; rather than the short radius build that is used for short lateral reach, small diameter wells applied to shallow reservoirs. Drilling and completion of horizontal wells In horizontal wells, the production casing (9 5/8” for example) is usually set just above or just within the reservoir at a fairly high angle (>70° say). In some cases a pilot hole (8 1/2” for example) may be drilled from that point, straight out of the casing through the reservoir. When the pilot hole has been evaluated and plugged back (or in the case where the pilot hole is omitted), the well is turned to horizontal and drilled through the reservoir to the planned length. Depending on the choice of well completion the reservoir-wellbore interface (e.g. slotted liner) will be installed at this time.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 21/70 Horizontal Well Trajectory and Build Radii The trajectory from surface to an entry point close to the reservoir is drilled using “conventional” drilling technology with a long radius (1°-6°/100 feet) build-up section to get the correct “sail” angle. The build-up into the reservoir is usually medium radius (8°-20°/100 feet). The entry point into the reservoir is called the “heel” and the far end of the well away is called the “toe”. In cases where there is a fluid contact above or below the well, the well is usually drilled parallel to that contact and the vertical distance to that contact is called the “standoff”. Directional control is to between 1.0 and 1.5 m in the vertical direction. The horizontal section control is to between 1.0 and TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 22/70 1.5 m in the vertical direction. The horizontal section can be in excess of 2000 m, the limit usually coming from reservoir requirements, completion or well access considerations, but not usually from drilling. Combined with extended reach, the toe of the well can be more than 10,000 meters horizontally from the surface well head. In some areas, e.g., Qatar, horizontal sections exceed 6 km.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 23/70 Geosteering The capability to drill and complete a horizontal well as discussed above is impressive but its success depends on being at the correct depth in the reservoir. Since the horizontal well encounters directly the lateral heterogeneity of the reservoir it must be steered in response to the formations and fluids penetrated. This steering process, by which a well trajectory is actively adjusted using real-time information, is known as geosteering. Its effectiveness is measured by how closely the well reaches its intended geological and hydrocarbon target. The real-time information can come from:  Microfossils to identify stratigraphic horizons  Cuttings to identify different marker lithologies and to differentiate reservoir from non-reservoir  Gas and oil shows to identify fluid contacts  LWD tools to identify lithology changes  Dedicated geosteering tools TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 24/70 The main applications of geosteering are: Horizontal steering on a fluid contact: Horizontal wells in oil rims are subject to severe gas cresting if any part of the well is close to the gas-oil contact. To make optimum use of such a well it may have to be positioned just above the oil-water contact. This can be done with resistivity tools when the water and oil zones have a large resistivity contrast. Steering close to a shale layer: It is often desirable to steer the well just under the shale that seals the reservoir using resistivity, gamma ray or porosity tools depending on conditions. Steering in a high permeability sand: Capillary forces usually mean that high permeability sands have lower water saturation than low permeability sands so there exists a resistivity contrast between these sands. A resistivity tool can be used to steer the wellbore through the high permeability sand. Horizontal Well Completion Some of the factors influencing well design are:  Cost  Sand control requirements  Zonal isolation and selectivity required for shut-off and stimulation operations

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 25/70  Operational constraints affecting access It is necessary to summarize the generic types of completion with their advantages and disadvantages: Sketches of the three types of completions are shown as follows: TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 26/70

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 27/70 Flow Regimes Vertical wells fully perforated across the reservoir section have a simple radial flow regime, with no vertical flow within the reservoir. For horizontal wells it is essential that fluid flows vertically in order to get to the level of the horizontal well. If vertical flow is not possible, (i.e. vertical permeability is zero) then the well will only drain oil from a horizontal layer whose thickness is the well diameter. In general over time a horizontal well has as a sequence of near wellbore, radial, linear, pseudo radial and hemispherical flow regimes. Reservoir Drainage Area Since the length of horizontal well that can be drilled is comparable to the well spacing between vertical wells, it is reasonable to hope that a horizontal well could have the same drainage area/volume as several vertical wells. Experience to date shows that in a field development plan a horizontal 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, 28/70 can typically replace between two and four vertical wells. This expectation needs to be confirmed by experience over the long term for a given field, as it does depend upon the individual structure and continuity. It can only be definitively known at the time of field abandonment. Productivity Improvement Factor (PIF) is then defined as the ratio of horizontal well productivity index (J H ) to vertical well productivity index (J V ), where both are measured at the same time in nearby wells assuming that production has stabilized in both wells. The PIF is one useful measure of the benefit of horizontal wells. For example, it is a good way of looking at the sensitivity to k V /k H . Figure below shows a case where a 500 m long well is placed in a 15 m thick reservoir. At the low end of the range the horizontal well performs more poorly than a vertical well while for k V /k H = 1 the horizontal well productivity is 4.3 times better than a vertical 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, 29/70 Benefits of Horizontal Wells Increased Exposure to the Reservoir The increase in reservoir exposure benefits in two ways. In the short term the production rate is higher and in the long term the cumulative production from a horizontal well is greater giving more reserves per well. Thus, the number of wells required to achieve a given plateau production rate and recovery factor will be less. Beliveau of Shell Canada conducted a review (SPE 30745) of more than 1000 horizontal wells comparing their hydrocarbon production performance to nearby vertical wells. Beliveau TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 30/70 plotted the distribution of productivity improvement factors (PIF’s) and found a lognormal distribution and deduced that; i) Horizontal wells in conventional reservoirs show a mode, or “most likely”, PIF = 2; a median, or “50/50”, PIF = 3 and a mean, or “average”, PIF = 4, and ii) Higher PIF are observed for heavy oil horizontal wells and horizontal wells in heavily fractured fields. The common rule of thumb is that a horizontal well is likely to provide 3-5 times more production than a vertical well. This is true on average but there is a large spread and around 25% of horizontal wells are considered “disappointing”. It is necessary to make “many trials” or, in other words, drill many wells to achieve the “3-5 times” objective.

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 31/70 More important is the cumulative recovery or reserves per well. Not very many horizontal wells have been abandoned so it is too soon to come to conclusions based on experience. A number of estimates have been made which fall in the range 2- 4 times the reserves of a vertical well. To achieve the same reserves will require 25% to 50% of the number of wells required in a conventional field development. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 32/70 Connection of Laterally Discontinuous Features Naturally fractured reservoirs are an important source of reserves especially in basins with extensive carbonate deposits. Frequently in carbonates the matrix porosity and permeability are too low for commercial production rates but wells intersecting the fractures can produce at high rates. The fractures are close to vertical in deeper reservoirs and a vertical well may or may not intersect fractures, depending on their fracture density. A horizontal well has a better chance of connecting many fractures. It must be aligned to intersect the fractures normally, which means that the stress direction at the time of fracture creation must be known. Faulting is another type of reservoir heterogeneity that horizontal wells can exploit. While drilling the horizontal

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 33/70 section the LWD (Logging While Drilling) response may suddenly go from reservoir to non-reservoir. If it is thought that this is due to traversing a fault then the well can be directed upwards or downwards in a search for the reservoir. It helps if there is good quality seismic available and the local faulting style is well understood. Changing the Drainage Geometry Horizontal wells usually have greater PI’s than vertical wells and, for a given productions rate, their drawdown will be lower. This lower drawdown helps delay the encroachment of unwanted fluids such as water or gas. For vertical wells this phenomenon is referred to as coning reflecting the shape of the TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 34/70 disturbance to the previously level contact. With a horizontal well the shape becomes a crest. Figure below shows for a water-oil interface that the drawdown must overcome the buoyancy force for the distorted water-oil contact to reach the well. Clearly, the greater the distance of the horizontal well above the Water-Oil-Contact the greater the drawdown can be without water production. The engineer’s job is to decide what this distance should be. This decision can be critical in an oil-rim reservoir or in the case of an unfavorable mobility ratio, such as often exists in heavy oil reservoirs. For an oil rim underlain by water the horizontal well must be placed parallel to the fluid contacts at a position which has been \ determined to be optimum with respect to the dominant reservoir drive mechanism (that is, gas cap expansion or aquifer influx). This results in improved well recoveries. This decision will also be dependent on the position of inter-reservoir shale barriers.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 35/70 Extending Field Appraisal Laterally The most common method of field appraisal has been to drill (many) vertical wells and, by logging and testing them, to build up a geological and reservoir model to use in development planning. This process can be extended laterally using horizontal wells. It can be especially powerful in delineating stratigraphic traps where reservoir quality may degrade over a few kilometers. Examples of where appraisal by horizontal wells brings advantages are:  Identification of complicated fracture networks  Combination of appraisal and development objectives  Appraisal of many fault blocks with one well  Ability to penetrate top reservoir from below, useful when top reservoir is difficult to map Disadvantages of Horizontal Wells So far the emphasis has been on the positive aspects of horizontal wells. As expected, there are also disadvantages.  The technology is more demanding of drilling and completion technology  Use of substandard rigs or drilling assemblies will result in a substandard end product (the horizontal 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, 36/70  The personnel employed should also be highly trained and used to working in an innovative manner. This applies especially to the directional drilling specialist who is responsible for implementing geosteering proposals  Horizontal wells usually have lower drawdown than vertical wells and may be more difficult to clean up  The options for monitoring, control and intervention are often limited  The cost of horizontal wells is higher, usually at least 20% higher These disadvantages can all be conquered given sufficient determination and good planning. Probably the most important consideration is that there should be powerful management commitment, prepared to accept some disappointing initial results as the learning curve is climbed. The Economics of Horizontal Wells Horizontal wells normally take longer to drill than vertical wells in the same reservoir and, as noted above, require high specification equipment and specialist personnel. Experience to date shows that the first few wells in a horizontal drilling campaign may cost around twice that of a vertical well and later the ratio drops into the range 1.2-1.5 as more wells are drilled.

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 37/70 The operating cost of horizontal wells has not been widely reported to date. The top-hole section should have operating costs similar to a vertical well but the horizontal section may have additional costs if intervention is required for production logging, stimulation or isolation using coiled tubing. Multilateral Wells A multi-lateral well is defined as “a well which has more than one vertical, inclined or horizontal hole drilled from a single site and connected back to a single or ‘mother’ well bore”. This section focuses on multi-laterals for which the branches are horizontal or close to horizontal in the reservoir. The main reason for drilling a multi-lateral well is to increase the return on investment through improved reservoir drainage even though the initial well cost is higher. For example reported that the reserves per multi-lateral in the Austin Chalk (Texas, USA) have been reported to be 1.8 times the reserves per single lateral while the cost was 1.4 times that of a single lateral. Since the late 1980’s there has been a rapid increase in the use of multi-laterals, similar to that experienced with horizontal wells about ten years earlier. This increase has been driven by a significant number of applications and the wells have had TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 38/70 various levels of sophistication in their design, from simple open hole sidetracks to wells where the branches could be re- entered or isolated selectively. These requirements have encouraged the service companies to invest in new methods of drilling and completing multi-laterals. The first multi-laterals were drilled in Russia in the 1950’s and 1960’s, an example is shown in the figure below. The technology was adopted and refined and the current examples are in the USA, Canada, \ Middle East and North Sea. A survey done recently of USA multi-laterals indicated typically two or three laterals per well and that 97% of applications were in reservoirs for which primary recovery was the dominant production mechanism. The application was usually in the case where horizontal wells were successful and further cost savings could be made by having fewer wellbores to surface. Combining a number of laterals into one multi-lateral thus made sense.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 39/70 Factors Influencing the Potential Application of Multilaterals There are many constraints in multi-lateral well design related to the operation of sidetracking out of the primary wellbore TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 40/70 and the shape of the reservoir(s) targeted by the laterals. For example the primary wellbore may be 8 ½ in hole with a gentle build angle while the sidetrack may be 6” hole with quite a severe build angle due to the small vertical distance between the junction and the reservoir. The laterals may have different lengths and different completions as a result of such geometric constraints. If the primary wellbore is highly deviated then the azimuthal separation between the laterals will be restricted. The process of multi-lateral well design often involves a few iterations between directional drillers, geologists and reservoir engineers before a satisfactory solution is found. Many factors influence the decision of whether to deploy a multi-lateral. They can be used in new or existing fields; but it is helpful to already have some experience of horizontal wells in the area. In some cases, a lateral can be drilled in a new direction to acquire exploration/appraisal data and depending on its success, either be retained for production/injection or abandoned. Interference may take place between laterals either in the reservoir or in the wellbore. If the laterals are being drilled in the same reservoir or in communicating reservoirs, the drainage areas will eventually overlap at later time. If this is so, then the resulting drainage area will be less than would be the sum of the drainage areas for the laterals individually, as indicated in the figure 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, 41/70 However, for low permeability reservoirs the transient period may last for a long time and significant acceleration of production will be achieved before interference effects reduce production. In non-communicating reservoirs, for example, in a sequence of stacked reservoirs, the same issues arise in a vertical well when deciding whether to perforate two independent flow units. Interference will take place in the wellbore unless a completely independent dual completion has been used. Generally it would be unwise to use a commingled completion if the reservoirs are in different pressure regimes because of the negative impact of cross flow. For reservoirs at the same pressure regime commingled production when producing dry oil causes no problem unless severe differential depletion takes place. With the advent of water cut in layer 1 a back pressure TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 42/70 will be experienced due to the higher density of the fluid in layer 1 causing undesirable cross flow into layer 2. Impact on Recovery and Rate In many cases multi-laterals do not increase ultimate recovery but simply accelerate production. This in itself can be beneficial in areas where costs and risks are high. To achieve both acceleration and improved recovery as shown in the sketch it is necessary to exploit the geology to the fullest, understanding the barriers to both lateral and vertical flow. The positioning of the laterals in the reservoir will be critical and it may be necessary to provide intervention possibilities to facilitate reservoir management.

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 43/70 Initiation Methods for Laterals Laterals can be initiated by a number of different methods:  Openhole sidetracks drilled with or without whipstock  Milling sidetracks from existing cased wellbores with full bore whipstock  Milling sidetracks with small diameter whipstock passed through tubing The first method is usual for carbonate reservoirs, particularly onshore where openhole completions are acceptable for horizontal wells. The second method is the method of choice for high rate wells where a large diameter lateral of significant length is required. Method three is good for coiled tubing drilled sidetracks. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 44/70 Principal Multilateral Geometries The three basic geometrical configurations are planar, stacked and opposing. The planar configuration is useful in naturally fractured reservoirs where there is some uncertainty about fracture orientation. Having three laterals with 45º angles between them is almost certain to intersect fractures at a reasonable angle to the original well, unless the spatial distribution of fractures is very clustered. The Dan field in the Danish sector of the North Sea is a good example of this type of well. The stacked configuration is designed for non-communicating layers and has been applied successfully in Dos Cuadros field offshore California by Unocal. The stacked configuration may be also useful in low permeability reservoirs where there is a long period of transient production and flow interference does not become significant for some time.

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 45/70 The dual-opposed configuration has the advantage of giving the largest drainage is for a given length of wellbore – it minimizes interference at the heel of the well. This configuration has been applied successfully in numerous wells in the Austin Chalk, Texas by URPC. Benefits of Multilateral Wells – Economic & Technical The economic benefits of multi-lateral wells arise from the fact that the conduit from surface to the reservoir only has to be drilled and completed once. Conventional wells require that each traversal of the reservoir required its own conduit to surface. Multilaterals can have a major impact offshore by increasing the production and pay section exposure for each slot available from a fixed platform or subsea template. Since the cost of platforms and templates is related to the number of slots, multilaterals can have a beneficial effect of reducing capital costs. This is especially true in new field developments where, in some cases, marginal fields can be transformed into economically viable developments. The same effect can benefit onshore development by reducing the pad size of the drilling location due to having fewer wells per pad. Onshore permit and planning costs can be reduced simply through having a smaller “footprint” on surface. There TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 46/70 may also be benefits in terms of reduced flowline and pipeline length. The environment can also benefit due to lower impact of a smaller surface presence. There may be some economic disadvantages that need to be recognized and managed at an early stage. The risk is now being concentrated into a smaller number of wells that may be dependent on new, untried technology. In the longer term there may be some additional operating costs due to uncertainties in reservoir and mechanical performance. One of the branches may experience premature water breakthrough and require installation of a scab liner or a plug. There may be an unexpected mechanical problem at a junction causing an undesirable leak of gas requiring intervention. These disadvantages are difficult to quantify but need to be addressed. Technical advantages of multi-laterals center on greater reservoir exposure at lower cost. All the advantages of horizontal wells can be captured at lower cost per reservoir foot. To reiterate:  Increased exposure to the reservoir  Connection of laterally discontinuous feature  Changing the geometry of drainage  Extending field appraisal laterally  Reduction in drilling costs and risk

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 47/70 It must be recognized that there are also technical disadvantages. Multi-laterals generally entail greater risk. Well intervention will be more difficult and reservoir monitoring and management that requires such intervention is currently limited in scope. Drilling and completion of multi-laterals introduces new difficulties in well control and also in impairment and cleanup of individual branches. Application of Multilateral Wells The applications of multi-lateral wells to oil and gas fall under two broad headings:  Improved commerciality of reserves  Data acquisition/delineation/risk reduction Improved commerciality of reserves is achieved either through:  Enhanced physical access  Reduced investment costs  Extended longevity of wells Enhanced physical access can be achieved through greater vertical access, improved areal drainage or higher production rate that gives acceleration of recovery. Reduced investment TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 48/70 costs arise due to increased reservoir footage exposed per mother wellbore. Extended longevity of wells comes about through extended production life before well reaches economic limit, improved reliability and the ability to defer production of unwanted substances such as sand, water or gas. Data acquisition/delineation/risk reduction comes about due to:  Well data  Reduced inter lateral spacing  More data per well Well data may provide increased geological and lateral step out data, especially through infill data. The speed of acquisition may be quicker leading to faster development. There are numerous applications of multi-lateral wells; the main reservoir applications will be the focus here:  Viscous oil  Layered reservoir  Faulted/compartmentalized reservoirs  Depleted and mature field development  Tight and naturally fractured reservoirs Viscous oil reservoirs have a productivity that is, in general, constrained by a poor mobility ratio, i.e. (Permeability /

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 49/70 Viscosity or k/  ) is low. To combat this and the associated high drawdowns, maximum formation exposure can be critical to achieving economic flow rates. In such cases, borehole area exposure can be more important than borehole diameter. The use of ultra-short radius wells of limited lateral length can be adopted to target such reservoirs which show a reduced formation thickness and low reservoir pressure. Layered reservoirs can be efficiently exploited using the stacked multi-lateral configuration. Care must be taken to plan carefully the degree of interaction of the laterals in the completion. If the pressure regimes are significantly different then it may be necessary to install separate tubings. These are strings isolated all the way to surface. The economics will be better if it is possible to commingle flow at the reservoir level. A reservoir in which the reserves are divided among many compartments is a good candidate for multi-lateral application especially if some of the compartments have reserves below the level at which an individual well could be justified. In drilling TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 50/70 such wells, knowledge of the fault locations and experience of drilling in the fault zone will be important. Placing of the junction relative to the faults will also be important. A high- resolution 3D seismic survey with good well control will make drilling such wells easier. Fields with many years of production history can lend themselves to multi-lateral application especially when the pace of development in various zones is different. Figure below shows two zones, one with good permeability, already quite well flooded, the other with lower permeability and still only partially flooded. The high permeability layer can produce quite well through a vertical wellbore but the low permeability is better suited to a horizontal wellbore so there is now a better chance of comparable oil rates in the two laterals.

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 51/70 Tight (low permeability) and naturally fractured reservoirs can be exploited using planar configurations with two or more laterals being used. For tight, unfractured reservoirs a number of branches at various angles will be appropriate, increasing the reservoir exposure cost effectively. For the naturally fractured case it depends on how well the fracture orientation is known. If this orientation were relatively poorly known then it would make sense to try a few different angles, testing the production rate in each lateral to determine which is the most favorable orientation. Besides these mainstream applications a number of more unusual applications of multi-laterals have been made:  Multi-laterals to appraise reservoir connectivity  Secondary and enhanced recovery applications  Special applications for marginal fields  Improving commerciality of tight gas fields  Multi-laterals for HP/HT development  Multi-lateral wells for fluid disposal TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 52/70  Multi-lateral to reinject produced water An interesting example of a multi-lateral application has been provided by Mobil North Sea Limited from their Galahad gas field in the UKCS sector of the southern North Sea. This low permeability gas field produces dry gas from the Rotilegendes sandstone. Previous wells have been either hydraulically fractured or drilled horizontally. The well objective for Galahad well 48/12a-7Z/7Y was to connect and appraise upper zones D, E and F. It was constrained to be a multi-lateral from an existing well in order to maintain production from the original wellbore. The operator wished to use adaptive technology in a simple fashion. The well completion used is shown in the adjacent sketch.

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 53/70 Characteristics of multi-lateral well costs can be summarized as follows:  Capital cost per well is higher  However, total field development cost will be lower due to the reduced well count  Operating cost – aim is to reduce operating cost  Well cost is very dependent on well complexity and completion system used TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 54/70 Extended Reach Wells The main characteristic of extended reach wells is a substantial horizontal displacement (HD) to (True) Vertical depth (TVD). A ratio of 2:1 is quite common. More recently BP has achieved a ratio of 10:1 at Wytch Farm. The size of the ratio depends on three factors:  TVD  Drilling conditions/lithology  Equipment/technology capabilities and limitations If the reservoir is very deep then the total length of the well restricts the size of the ratio. If drilling conditions are arduous leading to high torque or low rate of penetration then a high ratio will be difficult to achieve. Finally, the rig must be of a high standard with an adequate top drive and draw-works to handle the string weight and torque likely to be experienced. The unique advantage of extended reach wells is greater reach so that more area of reservoir can be accessed from one drilling center. A number of other advantages overlap with the advantages of either horizontal or multilateral wells:  Reduced number of wells  Greater wellbore contact area leading to lower drawdown  Improved connectivity of compartments and layers

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 55/70 There are a number of constraints associated with extended reach wells:  Concentrated risk due to the length and difficulty of the well  Higher unit well costs  Drilling limitations both in the topsides equipment and downhole due to high torque and drag  Completion limitations caused by the distance to the reservoir and the length in the reservoir  Flow monitoring and intervention are restricted by the well geometry A summary of extended reach wells from around the world is shown in the figure below. Wytch Farm well M11Y has the greatest HD:TVD ratio shown, later wells achieved horizontal departures greater than 10.5km. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 56/70 Extended Reach Drilling applications are most suitable for:  Thicker reservoirs. The wellbore will penetrate a larger borehole length from top to bottom of the reservoir if the angle is high  Multiple layers they will also be fully penetrated from top to bottom  Shallower formations. Depths less than 3000m TVD are favored by the current technology  Drilling from a central location Well known examples of ERD application are at Wytch Farm field, onshore UK by BP and in the Norwegian sector of the North Sea by Norsk Hydro and Statoil. In retrospect it would now be been possible to develop some of the North Sea giant fields using fewer platforms with ERD to provide greater

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 57/70 drainage area per platform, i.e., The Brent Field with one rather than the four platforms installed in the 1970's. ERD technology could also have been used at THUMS, Long Beach, California where artificial islands were created offshore to serve as drilling centers. Multiple Fractured Horizontal Wells In some circumstances it is beneficial to fracture horizontal wells, especially in fields where most vertical wells are fractured to achieve commercial rates. For reservoirs deeper than 500' (150m) the hydraulic fracture plane will be close to vertical and parallel to the direction of maximum stress. A vertical well will be suitably oriented to accept the flow of fluid from such a fracture. The orientation of the horizontal well will affect the connection with the fracture oriented to accept horizontal well may intersect such vertical fractures at angles from 0° (“Longitudinal”) to 90° (“Transverse”) in the figure 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, 58/70 This angle depends on the horizontal well orientation relative to the principal stress direction. The connection from reservoir to well via the fracture is influenced by this angle. For values close to 90° more than one fracture will be required. In this example production increases for up to four fractures are required and diminishing returns are reached for further fractures. In a closed box-like reservoir the PI ratio depends on the dimensionless fracture length 2x f /L, increasing more with 2x f /L as the number of fractures (n) increases.

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 59/70 An interesting comparison of a fractured and an unfractured horizontal gas well is shown in the figure below which shows the rate vs. time for different well configurations. An open hole horizontal well is compared with the cases of 1, 2, 3 & 5 fractures. The open hole horizontal well can produce more than the cases of 1 and 2 fractures and it is only when 3 or more fractures are created that the fractured well is superior. This effect is due to flow convergence with a small number of fractures. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 60/70 Smart / Intelligent Wells Smart wells are normally but not necessarily horizontal wells, equipped with downhole monitoring and control. To date, systems use surface readout so that data from downhole measurements of pressure, flow rate and flow stream composition are available at surface. These data can be processed and then used to adjust flow control devices commanded from surface. In principle the downhole information could be used directly for downhole control; but so far this step has not been taken. The main driver leading to smart wells has been the problem of reservoir management in horizontal wells. Reservoir

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 61/70 management has the objective of ensuring that the reserves of each flow unit are efficiently extracted with a minimum of unwanted fluids such as water. This requires the ability to close off perforated intervals and/or open new perforated intervals. The methods of perforating and of setting bridge plugs and scab liners in cemented casing used in conventional vertical wells are more difficult in horizontal wells. If the well were divided into a number of segments, each of which could be monitored and controlled separately, then more efficient reservoir management could be practiced. It could also reduce operating and processing costs as well as reducing workover frequency. Conventional workover methods as describe above have a number of drawbacks: Timing: Availability of equipment, crews, rig of Diving Support Vessel Cost: A typical straddle isolation (zone change) can take up to 10 days, plus the deferred oil during the intervention. A subsea zonal isolation treatment can be ten times more expensive than a platform job. One operator has quoted a cost in the North Sea of greater than £2 million. Risk: Straddle isolations have an inherent risk due to mis- settings, elastomer swelling and failure to retrieve. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 62/70 Constraints: Limitations to further downward development without drilling out plugs There are a number of cases which benefit from selective development and management:  Thin zones  Compartmentalized reservoirs  Vertically isolated sand units  Heterogeneous sand unit Thin zones

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 63/70 Compartmentalized reservoirs An individual well can be drilled to each compartment but the compartments may be too small to justify the cost of the four separate wells shown below. On the other hand, a horizontal well could access all these compartments with just one wellbore; but there may be a requirement to manage the drainage. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 64/70 The compartments could be sequentially completed but this may give an excessively low production rate and could also have high intervention costs each time an interval is to be changed. The best solution may be to use an “intelligent” well completion with monitoring and depletion control of each of the four compartments independently.

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 65/70 Coiled Tubing Drilling The two defining characteristics of coiled tubing drilling (CTD) are the use of continuous pipe spooled from a reel and the provision of drill-bit rotation by pumping drilling fluid through a mud motor located just behind the bit. A downhole thruster is also required to provide the necessary "weight on bit". There are many arguments in favor of CTD some of which are:  Drainage of remaining oil from smaller pockets  Improved production using multilaterals TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 66/70  CTD can be carried out through tubing  CTD operations can be done underbalanced (UBD) resulting in less formation damage  CTD can be deployed in situations where drilling facilities have been mothballed or previously removed  CTD can be used simultaneously with conventional drilling units  Additional production assessed through CTD can utilize “free” production plant capacity  Replacement of jackups and other mobile rigs for wellhead platform drilling  Small footprint  Reduced mobilization cost  Ever increasing world-wide availability  Shortage/high cost of alternative drilling facilities  Less manning required  Reduced cost because of more efficient operations  Safer operations with fewer personnel exposed to drilling hazards  More friendly to the environment The basic elements of a coiled tubing unit (CTU) are the coiled tubing reel, which stores the coiled tubing and from which it is reeled into the well, the gooseneck which acts as a guide, turning the coil through an angle of 120º before the injector head whose function is to push the CT into the well through the

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 67/70 stuffing box, BOPs, and lubricator the latter being attached to the top of the wellhead, as for wireline operations. A power skid to power the reel and injector head is located close to the coiled tubing reel. A control skid from which the operations are controlled is set up with a good view of the reel and gooseneck. Some of the technical advantages of CTD are:  No pipe handling  Continuous circulation  Electrical wireline can be run inside the CT  Underbalanced CTD is better than conventional UBD TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 68/70  Can drill through existing completion  Stand-alone system  Ease of mobilization and small footprint  Low noise level  CTD is safer than conventional drilling  Can be automated  Can handle higher wellhead pressures and downhole temperatures Some disadvantages of CTD are:  Smaller hole sized available which will limit production rates  Well length and weight on bit limitations  No pipe rotation which can lead to stuck pipe  Limit on length of horizontal section that can be drilled  No jointed pipe handling provided on a simple CTU – may be required for running casing or making up a tubing string  Buckling of CT may be a problem  Strength and coil diameter limitations  Life of string is limited by the number of trips into and out of the hole  With larger sized of CT there may be limitations in the size of reel that can be transported by road  Lifting capacity of offshore cranes may be a limitation

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TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 69/70  Small internal diameter of CT may impose hydraulic limitations While underbalanced CTD is an attractive option there are a number of disadvantages that need to be overcome:  The snubbing force and stripper pressure required increases as the WHP increases  Snubbing force increases with pipe size when WHP is held constant  Chances of mechanical failure on coil above the stripper increases with snubbing force  Increase in internal pressure in the coil reduces the cycle life  Larger diameter coil has lower cycle life than small diameter pipe  The low density drilling fluid used in UBD leads to less effective cooling/ cleaning of the bit The evolution of CTD in the 1990’s has seen a gradual increase in the number of new wells drilled using CTD. In 1990 twice as many CT wells were re-entries of old wells compared with the drilling of new wells. During the 1990’s the number of new CT horizontals drilled annually increased by a factor of three; while CT re-entries only showed a modest increase. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, e-mail: evren-ozbayoglu@utulsa.edu Group-1, Set-2, 70/70 The principal applications for CT re-entries are to extend the existing production interval or to reach new well targets. The completion diameter can be up to 41/2 in. outside diameter. Many of the re-entries can be through tubing. The newly drilled section may be a branch of a multilateral. BP in Alaska have performed over 40 such jobs have been done without pulling the existing completion. A thorough-tubing retrievable whipstock and window milling system has been used. The outturn cost was 50% less than the cost of a conventional workover. A variation on CTD through tubing re-entries has been done on Lake Maracaibo, Venezuela using conventional rigs with slimhole drillpipe and downhole motor. A Hybrid CTU is a unit equipped for pipe handling so that casing or tubing can be made up if required. Hybrid CTU is becoming widely applied in Alaska, but a number of offshore re-entries have been done using hybrid CTD in the North Sea. The latter have given underbalanced penetration of reservoirs with reduced mobilization costs. While technically successful they have not so far been particularly economic.

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