Well Completion

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 1/50 PE 4063 / 6463 – Well Completion GROUP – 1 Introduction to Well Completions SET 1 – Introduction The word "completion" means the conclusion of a borehole that has just been drilled. Completion is, therefore, the link between drilling the wellbore and the production phase. Completion involves all of the operations designed to make the well produce, in particular connecting the borehole and the pay zone, treating the pay zone, equipping the well, putting it on stream and assessing it. Pay zone is the reservoir rocks which contain oil and/or gas that can be recovered. Generally speaking, certain measurement and maintenance operations in the well along with any workover jobs that might be required also come under the heading of completion are considered. Therefore, completion begins with well positioning and ends only at well abandonment. Whatever the operational entity in charge of well completion and workover, its actions are greatly influenced by the way the well has been designed and drilled and by the production problems the reservoir might cause. The "completion man" will therefore have to work in close cooperation with the "driller" (who may both work in one and the same department), and also with reservoir engineers and production technical staff. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 2/50 After a well has been drilled, it must be properly completed before it can be put into production. A complex technology has evolved around the techniques and equipment developed for this purpose. Consequently, the selection of materials, equipment and techniques should only be made following a thorough investigation of the factors which are specific to the reservoir, wellbore and production system under study. Thus, completion engineer should be in coordination of many different professionals. As seen from the following figure, the completion engineers should be in contact with drilling engineers, reservoir engineers, production engineers, geologists, etc. Therefore, completion process required a massive teamwork.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 3/50 There are three basic requirements of any completion (in common with almost every oilfield product or service). A completion system must provide a means of oil or gas production (or injection) which is; i) Safe ii) Efficient iii) Economic Current industry conditions may force operators to place undue emphasis on the economic requirement of completions. However, a non-optimized completion system may compromise long-term company objectives. For example, if the company objective is to maximize the recoverable reserves of a reservoir or field, a poor or inappropriate completion design can seriously jeopardize achievement of the objective as the reservoir becomes depleted. In short, it is the technical efficiency of the entire completion system, viewed alongside the specific company objectives, which ultimately determines the completion configuration and equipment used. Well completion processes extend far beyond the installation of wellbore tubulars and equipment. Installing and cementing the production casing or liner, as well as logging, perforating and testing are part of the completion process. In addition, complex wellhead equipment and processing or storage TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 4/50 requirements effect the production of a well so may have some bearing on the design and configuration of the completion. Well Completion Planning Planning a completion, from concept through to installation, is a complex process comprising several distinct phases. Many factors must be considered, although in most cases, a high proportion can be quickly resolved or disregarded. Ultimately, it is the predicted technical efficiency of a completion system, viewed alongside the company objectives, which will determine the configuration and components to be used. Data Sources In order to select the suitable completion type as well as conduct a proper completion design, information should be gathered from different possible sources. Following figure summarizes the sources that are used for this purpose.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 7/50 assessed. For example, as the temperature and pressure of the fluid changes, the viscosity may rise or wax may be deposited. Both conditions may place unacceptable backpressure, therefore causes a dramatic reduction the efficiency of the completion system. While the downhole conditions contributing to these factors may occur over the lifetime of the well, consideration must be made at the time the completion components are being selected. Cost effective completion designs generally utilize the minimum acceptable components of an appropriate material. In many cases, reservoir and downhole conditions will change during the period of production. The resulting possibility of rendering the completion design or material unsuitable should be considered during the selection process. Wellbore Construction Wellbore construction factors can be categorized in the following phases; i) Drilling – The processes required to efficiently drill to and through the reservoir ii) Coring and testing – The acquisition of wellbore survey and reservoir test data used to identify completion design constraints iii) Pre completion stimulation or treatment – final preparation of the wellbore through the zone of interest for the completion installation phase. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 8/50 It is an obvious requirement that the drilling program must be designed and completed within the scope and limits determined by the completion design criteria. Most obvious are the dimensional requirements determined by the selected completion tubulars and components. For example, if a multiple string completion is to be selected, an adequate size of production casing (and consequently hole size) must be installed. Similarly, the wellbore deviation or profile can have a significant impact. Drilling and associated operations, e.g., cementing, performed in the pay zone must be completed with extra vigilance. It is becoming increasingly accepted that the prevention of formation damage is easier, and much more cost effective, than the cure. Fluids used to drill, cement or service the pay zone should be closely scrutinized and selected to minimize the likelihood of formation damage. Similarly, the acquisition of accurate data relating to the pay zone is important. The basis of several major decisions concerning the technical feasibility and economic viability of possible completion systems will rest on the data obtained at this time. A pre-completion stimulation treatment is frequently conducted. This is often part of the evaluation process in a test treat-test program in which the response of the reservoir formation to a stimulation treatment can be assessed.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 9/50 Completion Assembly Installation This stages marks the beginning of what is commonly perceived as the “completion program”. Considerable preparation, evaluation and design work has been completed before the completion tubulars and components are selected. With all design data gathered and verified, the completion component selection, assembly and installation process commences. This phase carries obvious importance since the overall efficiency of the completion system depends on proper selection and installation of components. A “visionary” approach is necessary since the influence of all factors must be considered at this stage, i.e., factors resulting from previous operations or events, plus an allowance, or contingency, for factors which are likely or liable to affect the completion system performance in the future. The correct assembly and installation of components in the wellbore is as critical as the selection process by which they are chosen. This is typically a time at which many people and resources are brought together to perform the operation. In general, completion components are broadly categorized as follows i) Primary completion, components ii) Auxiliary completion components. Primary completion components are considered essential for the completion to function safely as designed. Such components include the wellhead, tubing string, safety valves TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 10/50 and packers. In special applications, e.g., artificial lift, the components necessary to enable the completion system to function as designed will normally be considered primary components. Auxiliary completion components enable a higher level of control or flexibility for the completion system. For example, the installation of nipples and flow control devices can allow improved control. Several types of device, with varying degrees of importance, can be installed to permit greater flexibility of the completion. While this is generally viewed as beneficial, a complex completion will often be more vulnerable to problems or failure, e.g., due to leakage. The desire for flexibility in a completion system stems from the changing conditions over the lifetime of a well, field or reservoir. For example, as the reservoir pressure depletes, gas injection via a side-pocket mandrel may be necessary to maintain optimized production levels. Completion fluids often require special mixing and handling procedures, since; i) the level quality control exercised on density and cleanliness is high ii) completion fluids are often formulated with dangerous brines and inhibitors.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 13/50 treatment may be appropriate. There are various perforation treatments which may be associated with new or re- completion operations. Perforating acids and treatment fluids are designed to be placed across the interval to be perforated before the guns are fired. Used in overbalanced perforating applications, the perforating acid or fluid reduces the damage resulting from the perforating operation. Perforation washing is an attempt to ensure that as many perforations as possible are contributing to the flow from the reservoir. Rock compaction, mud and cement filtrate and perforation debris have been identified as types of damage, which will limit the flow capacity of a perforation, and therefore completion efficiency. If the objective of the treatment is to remove damage in or around the perforation, simply soaking acid across the interval is unlikely to be adequate. The treatment fluid must penetrate and flow through the perforation to be effective. In which case all the precautions associated with a matrix treatment must be exercised to avoid causing further damage by inappropriate fluid selection. Matrix treatment of the near wellbore area may be designed to remove or by-pass the damage. Hydraulic fracturing treatments provide a high conductivity channel through any damaged area and extending into the reservoir. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 14/50 Well Service and Maintenance Requirements The term “well servicing” is used to describe a wide range of activities including i) Routine monitoring ii) Wellhead and flowline servicing iii) Minor workovers (thru-tubing) iv) Major workovers (tubing pulled) v) Emergency response and containment. Well service or maintenance preferences and requirements must be considered during the completion design process. With more complex completion systems, the availability and response of service and support systems must also be considered. Wellbore geometry and completion dimensions determine the limitations of conventional slickline, wireline, coiled tubing or snubbing services in any application. Logistics Restraints imposed by logistic or location driven criteria often compromise the basic “cost effective” requirement of a completion system. Special safety and contingency precautions or facilities are associated with certain locations, e.g., offshore and subsea.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 15/50 Review of Some Basic Concepts The design of an efficient, safe and economic completion system is dependent on the acquisition of accurate data and the selection of appropriate components. Since the ultimate success of the completion systems is dependent on its successful installation, the installation procedures should also be given some consideration at this time. In many cases, several types of component can be used with equal success. Previous experience and knowledge of potential problem areas enable the selection process to be completed with a degree of confidence. There are enormous ranges of completion types and configurations in use worldwide. Most of which can be classified by the following general criteria.  Wellbore/reservoir interface, i.e., open-hole or cased hole completion  Production method, i.e., natural/artificial lift production  Producing zones, i.e., single /multiple zone production. Within each classification, completion design will vary according to the following reservoir and location characteristics;  Gross production rate  Well pressure and depth  Formation properties  Fluid properties  Well location TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 16/50 Production hydraulics, or the flow of fluids through the production tubulars can be a complex condition to asset and design for. However, several computer models are available to assist in completion designers achieve an efficient flow regime which minimizes the risk of problems later in the life of a completion. For example, most gas wells perform well upon initial completion. However, as the reservoir pressure depletes, liquid loading can occur which may restrict or even prevent production. Multiphase Flow Almost all wells produce a mixture of gas and liquids even though they may be distinctly classed as oil wells or gas wells. There are several flow regimes associated with the upward flow of multiphase fluids in vertical, or slightly deviated wellbores. Four conditions are generally recognized when describing flow in oil and/or gas wells. Bubble flow - characterized by a uniformly distributed gas phase as discrete bubbles in a continuous liquid phase. Bubble flow is further classified into bubbly and dispersed bubble flows, based on the presence or absence of slippage between the liquid and gas phases. In bubbly flow, relatively fewer and larger bubbles move faster than the liquid phase due to slippage. In dispersed bubble flow numerous tiny bubbles are transported by the liquid phase, causing no relative motion

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 19/50 annular/mist flow. The gas velocity required to sustain a stable annular/mist flow condition is known as the critical velocity. When analyzing or designing gas well completions, the critical velocity must be exceeded throughout the wellbore to ensure sustained, efficient liquid removal. A rule-of-thumb estimation frequently used for critical velocity is 10 ft/sec. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 20/50

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 21/50 Well System Analysis The process of optimizing production involves first understanding the reservoir fluid and deliverability parameters, then optimizing the design of each well component in the line of flow, wellbore, completion, and reservoir segments. The objectives of system analysis may be summarized as follows, the overall goal being systems optimization. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 22/50  Optimize the completion system to the reservoir deliverability  Identify restrictions or the limiting factors of production  Identify means of increasing the production efficiency Important completion parameters can be entered, and varied to enable the assessment of their contribution to the overall performance of the completion system. Optimization is generally a trial and error task of changing the parameter values used in each component until computer generated results match the desired well performance. This will establish a level of confidence in the computer generated results that can be carried to the next phase of the nodal analysis whereby parameters are changed to optimize the well for future performance behavior and anticipated workovers. Reservoir parameters are generally fixed, although the primary reservoir pressure may deplete during the producing life of the well. Fluid parameters are usually fixed except for ratios such as GWR, GOR, or GLR. The production system components to be optimized include the wellbore and completion configuration. Only a few parameters can be effectively changed to enhance the performance of most well systems:  Tubing or flowline  Wellhead or separator pressure (compression)

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 25/50 Then, 1 2 k A P P Q L          The linear flow model has little widespread application in the assessment of well productivity for real reservoirs since the flow geometry cannot be assumed to be linear. Production wells are designed to drain a specific volume of the reservoir and the simplest model assumes that fluid converges towards a central well. Steady-State Incompressible Radial Flow Defining the flow area as TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 26/50 2 A rh   Thus, Darcy’s equation can be written as   2 k rh P Q r       , w w r r P P   and , e e r r P P   . Here, P w is well flow pressure, P e is the reservoir pressure (also notated as P R ), r w is the well radius, and r e is the drainage radius. 1 2 e e w w P r P r Q P r kh r        After integration, ln 2 e e w w r Q P P kh r           e w P P  is the total pressure drop across the reservoir and is denoted the drawdown, and Q is the fluid flowrate at reservoir conditions.

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 27/50 The steady state radial flow equation for an incompressible fluid only truly applies when the reservoir is infinite in size and no pressure depletion occurs with time. It can be approximated by the performance of a well in a reservoir supported by an infinite aquifer provided the changing fluid mobility effects are negligible. It can also apply approximately for the following types of depletion provided little drop in reservoir pressure is experienced and assuming no marked changes occur in the properties of the flowing phases; i) highly supportive reservoir pressure maintenance with water injection or gas reinjection, ii) reservoir production associated with a substantial expanding gas cap. Semi Steady State Radial Flow of a Slightly Compressible Fluid Under these conditions, flow occurs solely as a result of the expansion of fluid remaining within the reservoir. The reservoir is frequently defined as being bounded since it is assumed that no flow occurs across the outer boundary. 0 e r r P r           , i.e., no pressure gradient exists across the outer boundary. Since the production is due to fluid expansion in the reservoir, the pressure in the reservoir will be a function of time and the rate of pressure decline P t   will be constant and uniform throughout the system. TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 28/50 The pressure profile with radius for the system will be constant but the absolute values of pressure will be time dependent. Production, since it is based upon the volumetric expansion of fluids in the reservoir, will depend upon the fluid compressibility which is defined as “the change in volume per unit volume per unit drop in pressure”, i.e., 1 V C V P     where C is the isothermal coefficient of compressibility. A reduction in pressure within the reservoir will cause an expansion in all of the fluid phases present, i.e., potentially oil, gas and water as well as a reduction in the pore space due to rock expansion. The isothermal compressibility should, for realistic evaluation, be the total system compressibility C t . For most reservoirs, C t is usually small, hence large changes in pressure will generate only limited fluid expansion and corresponding production. The application of Darcy’s law with the system compressibility equation applied to cylindrical reservoir volume, results in an equation which needs to be solved analytically to give

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 31/50 For a radial gas flow, Darcy’s equation takes the form 2 g r k h P Q r      Real gas law states that sc sc sc sc P Q PQ T Z T Z  Thus, 2 sc sc sc g sc T Z P r k h P Q T Z P r      Using the boundary condition for , w wf r r P P   and integrating, 2 ln w P sc sc w sc sc g P k h Z T r P P r Q T P Z            The integral term on the RHS can be handled either with a P 2 term after integration, or the Kirchoff integral commonly TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 32/50 referred to as the real gas pseudo-pressure function   m P where   2 2 2 w w o o P P P w g g g P P P P P P m P P P P Z Z Z                 A plot of  vs ln w r r       will yield a straight line with a slope 2 sc sc sc sc Q T P k h Z T  . Productivity Index Liquid Field measurements have shown that wells producing undersaturated oil (no gas at the wellbore) or water have a straight line IPR.   R wf Q PI P P   where Q is the flow rate and PI the “productivity index”. The productivity index provides a measure of the capability of a reservoir to deliver fluids to the bottom of a wellbore for production. It defines the relationship between the surface

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 33/50 production rate and the pressure drop across the reservoir, known as the drawdown. For a steady state incompressible fluid, productivity index is 2 ln R wf e w Q kh PI P P r r            For semi-steady state incompressible flow, productivity index is 2 3 ln 4 wf e w Q kh PI P P r r             TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 34/50 A theoretical basis for the straight line IPR can be derived using Darcy’s Law, radial inflow into the well along with other assumptions about rock and fluid properties. PI is a useful tool for comparing wells since it combines all the relevant rock, fluid and geometrical properties into a single value to describe (relative) inflow performance. The Absolute Openhole Factor (AOF or Q max ), is the flowrate at zero (bottomhole), wellbore flowing pressure. AOF, although often representing unrealistic conditions, is a useful parameter when comparing wells within a field since it combines PI and reservoir pressure in one number representative of well inflow potential. A straight line IPR can be determined from two field measurements; i) the stabilized bottomhole pressure with the well shut in (reservoir pressure), ii) the flowing, bottom hole, wellbore pressure at one production rate. The well’s inflow potential can then be calculated at any drawdown. Gas The compressible nature of gas results in the IPR no longer being a straight line. However, the extension of this steady state relationship derived from Darcy’s Law, using an average value for the properties of the gas between the reservoir and wellbore, leads to   2 2 R wf Q c P P  

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 37/50 2-Phase Straight line IPR are also not applicable to when two phase inflow is taking place, e.g. when saturated oil is being produced. Darcy's law is only applicable in single-phase flow within the reservoir. In the case of an oil reservoir, single-phase flow occurs when the bottomhole flowing pressure is above the depletion of a reservoir, the reservoir pressure continues to drop unless maintained by bubble point pressure of the reservoir fluid at the reservoir temperature. During the pressure falls below the bubble point pressure which results in the combination of single fluid injection or flooding. Consequently, during depletion the bottomhole flowing phase and two phase flow within the reservoir. This requires a composite IPR. Vogel’s work Most oil reservoirs will produce at a bottom hole pressure below the bubble point either i) Initially where the reservoir is saturated, ii) Or after production where the pressure in the pore space declines below the bubble point. The complexity of modeling the inflow in this case is that there is multiphase flow. The flow of the individual phase is governed by the pore space occupancy or saturation of that phase i.e. S o or S g , which is in itself a function of pressure. Further, each of the phases will only become mobile when its saturation exceeds a critical TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 38/50 value. Below this value the phase is static but the volumetric pressure of that phase constrains the flow of the mobile phase i.e. the relative permeability of the mobile phase for example for a gas oil system. The relative permeability of the system is defined by a series of saturation dependent curves which are specific to the fluids and rock system e.g. A number of approximate techniques have been proposed in order to define the relation between the pressure drop and the dynamics of two-phase production, such as those of Vogel etc. In Vogels' work, he simulated the performance of a solution gas

TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 39/50 drive reservoir, plotted the data and attempted to derive a generalized relationship. An equation was best fitted to the curve and had the general form of 2 max 1 0.2 0.8 wf wf P P Q Q P P                Behavior of IPR curve for different gas oil ratios at reservoir producing under bubble point pressure will be TU – PE 4063/6463 – Well Completion Fall 2023 Ozbayoglu M.E., 918-631 2972, evren-ozbayoglu@utulsa.edu Group-1, Set-1, 40/50 Fetkovich customized the IPR behavior based on gas flow conditions, which has already been given in the previous sections. Reservoir Drive Mechanisms A reservoir drive mechanism is a source of energy for driving the fluids out through the wellbore. It is not necessarily the energy lifting the fluids to the surface, although in many cases, the same energy is capable of lifting the fluids to the surface. There are a number of drive mechanisms, but the two main drive mechanisms are depletion drive and water drive. Other drive mechanisms to be considered are compaction drive and