PTRT 2331- Well Completion and Servicing

Chapter 1: Introduction to completion

1.1. Main factors influencing completion design 1.2. Overall approach to a well's flow capacity 1.3. Major types of completion configurations 1.4. Main phases in completion

Introduction

Developing oil and gas field and production is divided into 4 headings: - Reservoir Engineering - Drilling - Well completion and servicing -Surface production

These headings are inter-dependent of each other, for the purpose of this course we will be looking at well completion and servicing, a little of drilling and production.

We can see that completion and servicing starts with positioning a well for production and continues till abandonment of the well (work over)

Introduction

Well completion is not just about concluding a well, it is the link between drilling and production. Completion has to do with the operations designed to make the well produce from the pay zone to the surface.

Well Completion

Servicing – Work over

The servicing aspect of well completion handles both after drilling and during production (work over) A work over operation is - an extensive service on an oil and gas well which requires interventions in the wellbore itself to correct a problem with the well - a process of performing major or minor maintenance treatment on a well A work over job may be - performed by the oil company - contracted out to servicing companies that specialize in work over

Well completion incorporates the steps taken to transform a drilled well into a producing one. These steps include casing, cementing, perforating, gravel packing and installing a production tree.

Introduction Completion Personnel A completion man is the personnel/engineer that handles the completion operation. This completion man works in close cooperation with the driller, reservoir engineer, and the production engineer.

Class work 1. Why would a completion man work with the drilling engineer? 2. Why would a completion man work with the reservoir engineer? 3. Why would a completion man work with the production engineer?

Production engineers carry out the testing of formation. They supervise the gathering of pressure and fluid data to use in deciding whether the well is commercial, or worth completing. Production engineers are responsible for designing the completion and supervising its running at the well site. They also choose surface equipment to handle produced fluids, and they plan for long-term maintenance of the well's performance. Some companies divide the duties of completion and reservoir maintenance between two specialists, a completion engineer and a reservoir engineer, but the result is the same: a productive well planned and completed through decisions based on thorough geologic studies and on carefully gathered formation test and reservoir fluid data

1.1 Factors Influencing Completion Design

Several factors can influence the completion design, but the six main factors that will be considered in this course are:

-The purpose of the well/drilling (Types of Well) -The environment -Drilling -The reservoir -Production -Completion techniques

Types of well:

Purpose of Well

- An exploration or wildcat well - An appraisal or confirmation well - A development or exploitation well

Exploration Well

It is a well drilled in an unproven ground to test for oil after a positive seismic or other survey. The first step in field development is exploration well testing.

Two major objectives of an exploration well : 1. To determine the nature of fluid in the reservoir 2. To get the preliminary data on the reservoir, such as porosity, permeability, pressure, temperature, productivity and type of reservoir rock. • These measurements can be done during drilling and/or with wireline logging. • A temporary test string can be run in order to carry out production testing;

complications may arise during testing program on a well because the required data may be incomplete or become available at the last minute.

• The information obtained from exploration well helps to complete the data already available from geological and seismic surveys; the actual data is obtained from drilling.

• From all the information obtained, decision could be made whether to develop, not to develop the reservoir or to drill one or more further wells in order to obtain additional information.

Appraisal Well

It is a well drilled to measure the commercial potential (size & quality) of a discovery. It is drilled to further confirm and evaluate the presence of hydrocarbon in a reservoir that has been found by a wildcat. • The purpose of an appraisal well is to get further information from the

exploration well, these data could be: (i) Well potentiality (ii) Wellbore reservoir characteristics

- The off- wellbore permeability - The existence of heterogeneity, discontinuity or faults - The reservoir boundaries, a possible water drive

• All the data collected from different wells (exploration & appraisal wells) are used to make correlations between wells, thereby giving a picture on the scale/largeness of the field. Using the data, a decision is made whether to:

- Work out development schemes with corresponding production forecasts. - Develop the field or not. If to develop, choose among the schemes to draw up the development project.

Development Well

It is a well drilled in a proven producing area for the production of oil and gas. It is drilled to a depth that is likely to be productive in order to maximize the chance of success. A development well is a contrast of an exploration well. • The main purpose of this well is to bring the well into production. Though

important test are run on the well to: - Assess the condition of the well and to check how effective the completion has been - If needed, obtain further information about the reservoir

• Types of development wells: Production well, Injection well, Observation well - Production well: most numerous; it is aimed at optimizing productivity to

price ratio - Observation well: very few; it is aimed at monitoring variations in

reservoir parameters in a field such as fluid levels and pressure; wells unsuitable for production can be used as observation well

- Injection well: not numerous; it is aimed at improving hydrocarbon recovery, maintaining reservoir pressure, or getting rid of unwanted fluid such as brine

Thermal enhanced oil recovery by injection is classed to three categories : a) Steam Stimulation (Also known as cyclic steam injection, steam soak and

huff & puff): in this process steam (-+1000 bbl/day) is injected into a producing well for a specified period of time (usually 2 or 3 weeks )

Injection wells may be used as (to): 1. Dump wells: to get rid of unwanted fluids (oily water, etc) on the surface 2. Assist Production: where gas is directly injected into the tubing (through

annulus) to help lift the oil up to the surface 3. Assist Drive: water (or gas) injected into the reservoir to enhance drive

b) Steam Flooding : It is similar to water flooding and applies usually after steam stimulation

c) In Situ Combustion : Applies for extra heavy crude oil and is divided into 2 different processes : 1. Forward combustion

2. Reverse combustion

Environmental Factor

Drilling Factor

A work over rig or drilling rig may be used. A completion/work over rig is capable of only pulling tubing in and out of the well; it consists of a large truck with a draw works and a telescoping mast built on the bed and chassis. This rig only requires three men to operate and only works during the day time. NOTE: You cannot drill with this kind of rig unless it is equipped with a power swivel. The work over rig replaces drilling rig for completion. It is better to design completion using the same drilling rig in order to minimize time and cost. Using the drilling to complete a well, the following points must be taken into consideration. • The characteristics of the rig

• The type of equipment provided on it • Any additional units that may be available on it. E.g cementing

NOTE: It is very important to choose the drilling rig from the onset with due consideration given to the requirements specific to completion

The type of drilling rig Work over rig

Work over rigs

Provide the functions of drilling rig and workover rig. Hydraulic driving base can be moved transversely and lengthways.

Completion depends on the initial drilling program; drilling and casing program must be optimized taking production drilling requirements into consideration. The diameter of the borehole must be large enough to accommodate the equipment that will be installed in it

Drilling and casing program

Well Profile Vertical or directional well; deviation may limit or rule out the choice of some equipment or technique used to work on the well.

Casing program

Drilling into the pay zone and drilling fluid

It is best to design your drilling program based on an anticipation of potential hole problem and prevention of the formation damage. Pay zone may be damaged by drilling fluid or cement slurry reducing productivity. In case of damage, work over should analyze the problem and fix it for production

Cementing the production casing

It is necessary to examine the way the cementing job is carried out and tested. It is important that the cementing job between the formation and production casing provides a good seal.

Reservoir pressure

Well’s reservoir pressure is key to well’s natural flow capability. After a well has been completed, the initial pressure may be high, but as production depletes, the pressure reduces. It gets to a point where the natural pressure is not enough to produce; an artificial lift is then installed. A down hole pump might be installed while completing the well, whereby making it easier or unnecessary for work over job later.

Interfaces between fluids

• Uncontrolled interface between fluids reduce the productivity of the well by increasing the unwanted fluids in the reservoir. The unwanted fluids are also responsible for reduced reservoir pressure.

• Coning (the upward movement of water and/or the down movement of gas into the perforations of a producing well) occurs because of the change in oil-water contact or gas-oil contact profiles as a result of drawdown pressures during production.

Number of levels to be produced

Assuming you have different formation to drill and produce from, in a particular spacing unit, it may be easier for you to drill, complete and produce from several of them, instead of completing each formation differently. Though the work over job may be more frequent because of it complexity and also difficulty because the formation are depleting at a different rate.

Rock characteristics and fluid type

The characteristics of the rock and fluid type will directly influence completion, with respect to flow capacity, type of treatments, and production problems to be dealt with. Some of these problems may be: 1. Borehole instability/ slough shale: this is the most troublesome problem posed by drilling into shale. 2. Clay particle swelling or dispersion: this problem is inherent in sandstone formation that contains water sensitive clays.

Parameters to consider:

Production profile

Reservoir Factor

C

B A Pro

du

ctio

n R

ate

Time

Safety

Production Factor

Horizon disaster due to bad safety planning https://www.youtube.com/watch?v=4XtusjA5YEE

https://www.youtube.com/watch?v=vWh9jDei-og

https://www.youtube.com/watch?v=aN2TIWomahQ

Flowing well or artificial lift

Operating conditions

Anticipated measurement or work over operations

Completion Techniques

Completion Design Synthesis

This is about how completion is designed for - Exploration or appraisal well: it should involve level(s) that may be tested,

type and duration of test to be run - Development well: it involves level(s) to be produced, production or

injection profile required

1.2 Flow capacity of well

-Base Equations -Analysis of different terms

Base Equation A well’s flow depends on 1. The existing pressure difference, i.e., reservoir and borehole pressure. 2. Parameters that involve the type of reservoir and in-place fluids.

• The most basic formation test data are bottomhole static and bottomhole flowing pressure. - Static bottomhole pressure is the pressure at the producing formation when

the well is shut in and pressure has built up to maximum level. - Bottomhole flowing pressure is the pressure at the producing formation face

when the well is allowed to flow. - The ability of the well to produce its fluids depends on the difference

between static shut-in and flowing bottomhole pressure, which production engineers call drawdown.

Reservoir and Borehole Pressure

Drawdown Buildup

Static

• A drawdown test is a formation test technique in which a shut-in well is opened and its bottomhole pressure is measured continuously as it drops to stable flowing pressure.

• On the other hand, the production engineer may shut in a flowing well and measure increasing bottomhole pressure as it builds to a stable shut-in pressure. This procedure is called a buildup test.

• When it is not economical to shut in a well and cease its production during a drawdown or a buildup test, production engineers may choose a multirate flow test, in which pressure behavior is measured while the well's rate of flow is changed with downhole or surface valves.

The productivity index is generally measured during a production test on the well. The well is shut-in until the static reservoir pressure is reached. The well is then allowed to produce at a constant flow rate of Q and a stabilized bottom-hole flow pressure of pwf.

Since a stabilized pressure at surface does not necessarily indicate a stabilized pwf, the bottom-hole flowing pressure should be recorded continuously from the time the well is to flow.

Productivity Index

The productivity index (PI or J) is defined as the flow rate per unit drawdown pressure and serves as an indication of the production potential of a well (the ability of the well to produce). For a water-free oil production, it is defined as:

For example, if a well flows at a 1000 stb/d with a flowing (sandface) pressure of 1500 psi and at an average reservoir pressure of 2000 psi, then the productivity index is: PI = 1000 / (2000 - 1500) = 2 stb/d / psi

Since a stabilized pressure at surface does not necessarily indicate a stabilized pwf, the bottom-hole flowing pressure should be recorded continuously from the time the well is to flow. The productivity index is then calculated from the above Equation.

The PI is a valid measure of the well productivity potential only if the well is flowing at pseudo-steadystate conditions. In order to accurately measure the PI of a well, it is essential that the well is allowed to flow at a constant flow rate for a sufficient amount of time to reach the pseudo-steady-state as illustrated. During the transient flow period, the calculated values of the PI will vary depending upon the time at which the measurements of pwf are made.

Theoretically:

Well Inflow Performance Once the PI is know the above equation can be re-arranged to determine the deliverability rate as follows:

This equation is only valid for a well in an unsaturated reservoir. For wells in saturated reservoirs or for gas wells, the relationship is not as straight forward, and the simple relationship described above does not apply. In these situations either an IPR (for oil) or AOF (for gas) analysis should be performed.

Oil inflow performance For multiphase flow, a curved relationship existed between flow rate and pressure; the straight-line productivity index does not apply.

For reservoir pressures less than the bubblepoint pressure, the reservoir fluid exists as two phases, vapor and liquid, and techniques other than the productivity index must be applied to predict oil well performance.

Bottom Hole

Re

serv

oir

IPR empirical approach - Vogel Vogel’s empirical inflow performance relationship (IPR) is based on computer simulation results and is given by

In certain circumstances, both single-phase and two-phase flow may be occurring in the reservoir. This results when the average reservoir pressure is above the bubblepoint pressure of the reservoir oil while the flowing bottomhole pressure is less than the bubblepoint pressure.

The relationship that yields the maximum oil production rate is then

Single- and two-phase flow

IPR theoretical approach

The composite IPR couples Vogel’s IPR for two-phase flow with the single-phase productivity index.

When the flowing bottomhole pressure is greater than or equals the bubblepoint pressure:

When the flowing bottomhole pressure is less than the bubblepoint pressure:

Example 1 Construct IPR curve of a well given the following data: Average reservoir pressure = 5000 psia Bubble point pressure (pb) = 3000psia Tested flowing bottom hole pressure = 4000 psia Tested production rate (flow rate) = 300 stb/d

First calculate the PI, which is constant because it is the slope of IPR J = 300/(5000-4000) = 0.3 stb/d-psia

First calculate the PI, which is constant because it is the slope of IPR J = 300/(5000-4000) = 0.3 stb/d-psia

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0.0 200.0 400.0 600.0 800.0 1000.0 1200.0

Bo

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flowrate

pwf q

0 1100.0

500 1072.2 1000 1022.2

1500 950.0

2000 855.6 2500 738.9

3000 600.0

3500 450 4000 300

4500 150

5000 0

Calculate qmax

qmax= 0.3(5000 – 3000 + 3000/1.8) = 1100

IPR

Gas inflow performance

Empirical Method

Theoretical Method

Forchheimer Model

Backpressure Model

A, B, C, and n are empirical constants to be determined from test points

Example

Solution Empirical Deliverability.xls

IPR Curves – Theoretical

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p - Approach

p2 - Approach

Reservoir pressure

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Gas Production Rate (Mscf/d)

Forchheimer

Backpressure

Reservoir pressure

IPR Curves – Empirical

pwf (psia) q (Mscf/d)

Forchheimer Backpressure

15 1704 1709

239 1701 1706

464 1693 1698

688 1679 1683

913 1660 1663

1137 1634 1637

1362 1603 1605

Pwf q

0 1718

1000 1658

2000 1477

3000 1162

4000 687

5000 0

Deliverability testing goes under several names such as "Back-Pressure Testing", "4-Point Testing" , "Open Flow Potential Testing", and "AOF Testing". The terms "Open Flow Potential" and "Absolute Open Flow" refer to the theoretical maximum flow rate from the reservoir. A "Deliverability Test" usually requires the well to be produced at several rates.

More analytical and empirical methods and terminologies

• The achievable oil production rate from a well is determined by wellhead pressure and the flow performance of production string, that is, tubing, casing.

• The flow performance of production string depends on geometries of the production string and properties of fluids being produced. The fluids in oil wells include oil, water, gas, and sand.

• Wellbore performance analysis involves establishing a relationship between tubular size, wellhead and bottom-hole pressure, fluid properties, and fluid production rate.

• Understanding wellbore flow performance is vitally important to production engineers for designing oil well equipment and optimizing well production conditions.

• Oil can be produced through tubing, casing, or both in an oil well depending on which flow path has better performance. Producing oil through tubing is a better option in most cases. The traditional term tubing performance relationship (TPR) is used (other terms such as vertical lift performance (VLP) or vertical flow performance (VFP) have been used). However, the mathematical models are also valid for casing flow and casing-tubing annular flow as long as hydraulic diameter is used.

Well Outflow Performance

The flow path through the wellbore may include flow through perforations, a screen and liner, and packers before entering the tubing for flow to the surface. The tubing may contain completion equipment that acts as flow restrictions. In addition, the tubing string may be composed of multiple tubing diameters or allow for tubing/annulus flow to the surface. At the surface, the fluid must pass through wellhead valves, surface chokes, and through the flowline consisting of surface piping, valves, and fittings to the surface-processing equipment. The pressure drop experienced as the fluid moves from the reservoir sandface to the surface is a function of the mechanical configuration of the wellbore, the properties of the fluids, and the producing rate.

Pressure loss through the wellbore

Relationships to estimate this pressure drop in the wellbore are based on the mechanical energy equation for flow between two points in a system as

For most practical applications, there is no work done by or on the fluid and the kinetic energy correction factor is assumed to be one.

We are interested in the determination of TPR and pressure traverse along the well string. Tubing Performance Relationship (TPR) is defined as a relation between tubing size, fluid properties, fluid flow rate, wellhead pressure, and bottom hole pressure. In most engineering analyses, it is desired to know the bottom hole pressure at a given wellhead pressure and flow rate in a well. There are two theoretical approaches: 1. Single-Phase Flow: assumes only a single phase is flowing (gas only or oil only) 2. Mist Flow: assumes multiple phases (up to four: water, oil, gas, sand) are

flowing through the tube due to high velocity. When natural gas flows to the surface in a producing gas well, the gas carries liquids to the surface if the velocity of the gas is high enough. A high gas velocity results in a mist flow pattern in which liquids are finely dispersed in the gas. Consequently, a low volume of liquid is present in the tubing or production conduit, resulting in a pressure drop caused by gravity acting on the flowing fluids.

Methods to estimate the pressure drop in tubulars for single-phase liquid, single-phase vapor, and multiphase flow are based on this fundamental relationship:

Single-phase liquid flow Single-phase liquid flow is generally of minor interest to the petroleum engineer, except for the cases of water supply or injection wells. In these cases, the friction factor, f, is a function of the Reynolds number and pipe roughness. The friction factor is most commonly estimated from the Moody friction factor diagram. The friction factor is an empirically determined value that is subject to error because of its dependence on pipe roughness, which is affected by pipe erosion, corrosion, or deposition.

Single-phase flows

Single-phase gas flow There are several methods to estimate the pressure drop for single-phase gas flow under static and flowing conditions. These methods include: • The average temperature and compressibility method • The original and modified Cullendar and Smith methods

Multi-phase flows

Multiphase flow of fluids in pipe is much more complex than the single-phase flow problem because there is the simultaneous flow of fluids; the problem is further complicated as the velocities, fluid properties, and the fraction of vapor to liquid change as the fluid flows to the surface due to pressure changes. Flow patterns or flow regimes relate to the distribution of each fluid phase inside the pipe. This implies that a pressure calculation is dependent on the predicted flow pattern. There are four flow patterns in the simplest classification of flow regimes: • Bubble flow • Slug flow • Transition flow • Mist flow, with a continually increasing fraction of vapor to liquid from

bubble to mist flow

Flow regimes classification of flow regimes: • Bubble flow • Slug flow • Transition flow • Mist flow

Bubble flow Slug flow Annular Flow Churn Flow

http://www.thermopedia.com/video/4721/?links=bubble1,slug_or_plug,churn,annular,wispy_annular&names=Bubble_Flow,Slug_or_Plug_Flow,Churn_Flow,Annual_Flow,Wispy_Annual_Flow

http://www.thermopedia.com/video/4721/bubble1

http://www.thermopedia.com/content/2/

Choke Performance

Multiphase flow occurs in almost all producing oil and gas/condensate wells. Every flowing well has some devices to control the flow rate for maintaining sufficient back pressure to prevent formation damage (sand production), to protect surface equipments, to prevent water/gas coning, to stabilize the flow rate and to produce the reservoir at the most efficient possible rate. • Chokes are one of the most important flow controllers in oil and gas

producing wells. • Accurate modeling of choke performance and selection of optimum choke

size is vitally important for a petroleum engineer in production from reservoirs due to high sensitivity of oil and gas production to choke size.

• Flow through a surface choke can be described as either critical or sub-critical. Critical flow occurs when the velocity through the choke is greater than the sonic velocity of the fluid.

• Chokes are classified as nozzle-type and orifice-type with fixed (or adjustable) diameters.

Both the IPR and the TPR or VFP (vertical flow performance) relate the wellbore flowing pressure to the surface production rate.

The IPR represents what the reservoir can deliver to the bottomhole and the TPR (or VFP) represents what the well can deliver to the surface.

Combined, the intersection of the IPR with the VFP yields the well deliverability, an expression of what a well will actually produce for a given operating condition. The role of a petroleum production engineer is to maximize the well deliverability in a cost-effective manner. Understanding and measuring the variables that control these relationships (well diagnosis) becomes imperative.

Well Deliverability

Combining IPR with TPR identifies the operating point.

Improving deliverability

Analysis of Terms

Major Types of Completion Configurations

Basic Requirements

Pay Zone - Bore Hole Connection Two main types of connections between the pay zone and the bore hole: Open Hole Completion (barefoot completion) Cased Hole Completion

For example, gravel packing

Open Hole Completion

Also, without any casing or liner installed, selective treatments or remedial work within the reservoir section are more difficult.

Open Hole Completion is used where there is just one zone which is either very well consolidated or provided with open-hole gravel packing for sand control. This is valid as long as there are theoretically no interface problems. Because of this, open hole completion is seldom chosen for oil wells.

An open-hole completion refers to a well that is drilled to the top of the hydrocarbon reservoir. The well is then cased at this level, and left open at the bottom. Also known as top sets and barefoot completions, open-hole completions are used to reduce the cost of casing where the reservoir is solid and well-known.

Note: liner not cemented (needs hanger) Perforated liner: --------- Perforated cemented liner: <

Mainly used when there are interface problems and/or when there are several levels to produce from. They are more common.

Cased Hole Completion

Main configurations of production strings

Conventional Completion

Depends on 1. Number of levels due for production

2. If a production string (tubing) is used (conventional completion) or not (tubingless completion).

a single tubing and a production packer is used. A production packer is a seal between the casing and the tubing.

Two types of single-zone completion: With tubing and packer With tubing alone

Single-zone Completion

Packer: http://www.youtube.com/watch?v=TKHfDSnjbXE

In the past, the technique of producing several levels together through the same tubing was used. It required only a minimum amount of equipment. However, the subsequent reservoir and production problems that were experienced have caused this practice to become much less common.

Multiple Zone Completion

Here several levels are produced in the same well at the same time (parallel tubing string and tubing – annulus completion) or different time (alternate selective completion).

Dual String

Alternative Selective

Single Zone Tubingless Completion mostly used in the middle east Multiple Zone Tubingless Completion mostly used in U.S.A

Miniaturized Completion involves multiple zone tubing less completion, equipped with little macaroni tubing so that each cemented casing has a conventional single or more tubing-annulus completion. It is mostly used in USA.

Tubingless Completion

Uses no tube; so, no packer is required Used in certain regions and only under specific conditions

Main Phases in Completion

Conditioning the borehole

Open hole Drill bit is run back in the hole and circulated in order to get uniform mud; mud can be replaced with completion fluid

Cased hole

Remedial cementing

To correct inadequate cement bond quality; casing is perforated and cement is injected under pressure

Re-establishing payzone-borehole communication

Reading assignment

List and briefly discuss the main stages in completion