Chapter 1 - Introduction To Production Technology

Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Chapter 1 – Introduction to Production Technology Table of Contents 1.1

Scope ................................................................................................. 1-1

1.2

Contribution to Oil Company Operations ....................................... 1-2

1.3

Time Scale of Involvement............................................................... 1-3

1.4 Key Subject Areas in Production Technology ............................... 1-3 1.4.1 Primary Reservoir Energy............................................................ 1-4 1.4.2 Well Productivity .......................................................................... 1-7 1.4.3 Well Completion .......................................................................... 1-8 1.4.4 Well Stimulation ......................................................................... 1-11 1.4.5 Associated Production Problems ............................................... 1-12 1.4.6 Remedial and Workover Techniques......................................... 1-13 1.4.7 Surface Processing.................................................................... 1-14 1.5 The Composite Production System .............................................. 1-15 1.5.1 General Description ................................................................... 1-15 1.5.2 Utilisation of Reservoir Pressure ............................................... 1-16 1.6 Supplementing Reservoir Energy ................................................. 1-18 1.6.1 Fluid Injection into the Reservoir ............................................... 1-20 1.6.2 Supplementing the Vertical Lift Process .................................... 1-21

CHAPTER 1 Introduction

Curtin University of Technology Department of Petroleum Engineering

CHAPTER 1 Introduction

Master of Petroleum / Petroleum Well Engineering Production Technology

Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Chapter 1 – Introduction to Production Technology The role of the Production Technologist is extremely broad. However currently within the operating companies in the petroleum industry, the role and responsibility of a Production Technologist does vary between companies, but can be broadly said to be responsible for the production system. 1.1

Scope

The production system is a composite term describing the entire production process and includes the principal components as follows: (1)

The reservoir – its productive capacity and production characteristics.

(2)

The wellbore – the production interval, the sump and the fluids in the wellbore.

(3)

Production Conduit – comprising the tubing and the tubing components.

(4)

Wellhead, Xmas Tree and Flow Lines.

(5)

Treatment Facilities.

From the above definition it can be seen that the responsibilities of Production Technology cover primarily downhole aspects of the system but they also extend to some of the surface facilities and treatment capabilities. Production Technology is so defined as to be a blend of engineering and chemistry. The role of the Production Technologist is one of achieving optimum performance from a production system and to achieve this the technologist must understand fully the chemical and physical characteristics of the fluids which he or she seeks to produce and also the engineering systems which he or she will utilise to control the production/injection of fluids, efficiently and safely. The importance of the production chemistry input has only recently been widely acknowledged. It is clear that the physical chemical processes, which take place in the production of fluids can have a tremendous impact on project economics in addition to the production capacity and safety of the well. The main topics covered by a production technologist can be identified as: (1)

Production Engineering:   

(2)

Fluid Flow. Reservoir Dynamics. Equipment Design, Installation, Operation, and Fault Diagnosis.

Chemistry:  

CHAPTER 1 Introduction

The Fluids – produced, injected and treatment fluids. The Rock – mineral, mineralogy, physical chemical properties and rock response.

Page 1-1

Curtin University of Technology Department of Petroleum Engineering

1.2

Master of Petroleum / Petroleum Well Engineering Production Technology

Contribution to Oil Company Operations

Production Technology contributes substantially as one of the major technical functions within an operating company. As with any commercial venture, the overall incentive will be to maximise profitability at the sharp end of project economics and it is this area of operations that involves the production technologist. The modern requirement for high level technology, which enables zonal isolation, production of multiple zones from the same wellbore, very high production rates, isolation of water production, multiple wellbores within a single well etc., costs a substantial amount of money and that requires careful planning and execution. The wells must be optimally designed to suit the purpose and meet the objectives of the well and the field. The production technologist’s involvement should start during the drilling of the well in minimising formation damage and setting the necessary casing strings to meet the objectives of the completion string and hence those of the well. The main objectives normally encountered in an oil company operation could be broadly classified as: (1)

Cash flow To maximise both cashflow and recoverable reserves in the shortest time possible, this will normally require the maintenance of the wells in an operational state with:   

(2)

Maximum production rates Maximum life Minimum down time

Costs The costs associated with the completion and production of a well can be split into two categories namely, fixed and direct costs and both these need to be minimised. The fixed costs being those associated with conducting the operation and the direct or variable costs being associated with the level of production and the nature of the operation. The latter costs are therefore defined in terms of cost per barrel of oil produced. On this basis the production technologist would seek to minimise the overall variable costs through minimising:     

Capital costs Production costs Fluid treatment costs Well workover costs Well abandonment costs

From the above, it can be seen that the bulk of the operations for which the production technologist is responsible or has major inputs into, is crucial in ensuring that the companies’ operations are safe, efficient and profitable. CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

1.3

Master of Petroleum / Petroleum Well Engineering Production Technology

Time Scale of Involvement

The trend within operating companies currently is to assign specialist task teams to individual fields or groups of wells. The team consists of specialists from all relevant disciplines. This ensures that there is a forward looking plan for continuous improvement and optimised production. The production technologist is involved in the initial well design and will have interests in the drilling operation from the time that the reservoir is penetrated, continuing on throughout the production life of the well, to ultimate abandonment. Thus the production technologist will contribute to the company operations on a well from the initial planning stage to final abandonment. The inputs in chronological order to the development and the operation of the well are listed below: PHASE

INPUT/ROLE

Drilling Completion Production Workover/Recompletion

Casing string design, Drilling fluid Selection Design/installation of completion string Monitoring well and Completion performance Diagnosis/Recommendation/Installation of new or improved production systems Identify candidates and procedures

Abandonment

1.4

Key Subject Areas in Production Technology

Production Technology is both a diverse and complex area. With the ongoing rapid development of the Petroleum Industry, as a result of the spiralling oil prices seen in recent times, the scope of the technological activities continues to expand and as always increases in depth, complexity and cost. There are several key subject areas that encompass production technology and these are listed below: -

Understanding of Primary Reservoir Energy Well Productivity Well Completion Well Stimulation Associated Production Problems Remedial and Workover Techniques Surface Processing Production Optimisation

Each area listed above will be considered briefly in this chapter with the assumption that the production technologist will have a sound knowledge of reservoir engineering fundamentals.

CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

1.4.1

Master of Petroleum / Petroleum Well Engineering Production Technology

Primary Reservoir Energy

A reservoir rock will produce naturally as a consequence of the fluid which it contains, existing at high pressure within the reservoir rock that is in a state of compaction. Thus the reservoir as such contains an enormous amount of energy in the form of compressive energy which can be utilised to allow fluid to be produced from the reservoir, through expansion, into a well and then on to surface and finally into treatment facilities. The response of the reservoir to the pressure depletion process, which occurs during production, will be dynamic and the fluid remaining in the reservoir will change both in terms of its volume, composition, pressure and other rock and fluid properties. The manner in which the reservoir system responds to the depletion process will be naturally governed by the drive mechanism inherent in the reservoir. The long-term production capacity of the reservoir will be dependent on the dominant drive mechanism present within the reservoir. The depletion effects can be supplemented by the injection of a fluid, either water or gas back into the reservoir depending on the hydrocarbon fluid properties. Once the reservoir delivers fluid to the wellbore, sufficient pressure energy needs to exist to lift the fluid to surface if the well is to operate on natural flow. In the event that insufficient energy exists to allow production to occur at an economic rate, the well may require assistance by the application of an artificial lift technique. The production of a reservoir fluid under its own energy is dependent on the reservoir pressure being sufficient to counteract the hydrostatic head (from surface) generated by the fluids, the frictional pressure drop generated by the flowing fluid in the production tubing and the minimum wellhead pressure that will be required to feed the production separator. The removal of fluids from the reservoir will cause the pressure in the reservoir to drop and this loss of energy is compensated to a degree by one or more of the following mechanisms: (1) (2) (3) (a) (b) (c) (d)

Compaction of the reservoir rock matrix. Expansion of the connate water. Expansion of hydrocarbon phases present in the reservoir: If the reservoir is above the bubble point then expansion of the oil until the bubble point is reached. If the reservoir is below the bubble point then expansion of the oil and gas phases. Expansion of any overlying gas cap. Expansion of an underlying aquifer resulting in water influxing into the portion of the reservoir that was vacated by the produced fluids. The strength of the aquifer will determine the pressure support provided.

CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

In most cases, as oil is produced, the system cannot maintain its pressure and the overall pressure in the reservoir will decline. The pressure stored in the reservoir in the form of compressed fluids and rock represents the significant natural energy available for the production of fluids from the reservoir to surface. The mechanism by which a reservoir produces its fluids and compensates for the production is termed the reservoir drive mechanism and refers to the method by which the reservoir provides the energy during production. There are a number of drive mechanisms (listed below) and a reservoir may be under the influence of one or more of these mechanisms simultaneously. (a)

Solution Gas Drive If oil is found initially in the reservoir above its bubble point, the loss of reservoir energy due to the removal of the produced oil will be compensated for by an expansion of the oil left in place within the reservoir until the bubble point is reached. This will by necessity lead to a reduction in pressure and eventually the pressure within the reservoir will drop below the bubble point. Gas will then come out of solution and any subsequent production of fluids will lead to an expansion of both the oil and gas phases within the reservoir. A reservoir found above its bubble point is referred to as a saturated reservoir as no more gas can be absorbed by the oil at that pressure. The field’s producing gas/oil ratio rises quickly as the bubbles link up and begin to flow, and may increase to as much as ten times its initial value. Oil production rates fall quickly once the gas/oil ratio begins to rise. Wells must be placed on artificial lift early in their life. Initially, little or no water is produced. As the reservoir pressure continues to fall, the cumulative gas production eventually reaches a point where a significant portion of solution gas liberated in the reservoir is produced to surface and oil production diminishes.

(b)

Gas Cap Expansion Drive If a reservoir is found at its bubble point, it may have a gas cap containing a free gas column above the oil leg. Drive energy in a gas cap drive reservoir is provided by the expansion of the initial gas cap combined with the energy provided by the solution gas released from the oil. Reservoir pressure drops more gradually than in a solution gas drive due to the pressure support provided by the gas cap. The field gas/oil ratio rises continuously as the expanding gas cap reaches the wells situated higher up on the structure.

CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

(c)

Master of Petroleum / Petroleum Well Engineering Production Technology

Water Drive Drive energy in a water drive reservoir is provided primarily by water influx from an aquifer in pressure communication with the oil zone. In strong water drives, reservoir pressures are maintained and the field gas/oil ratio remains low as water moves in to replace the produced fluids. In a water drive reservoir, the oil zone is in communication with an aquifer providing the bulk of the reservoir’s drive energy. As oil is produced, the water in the aquifer expands and moves into the reservoir, displacing oil. Depending on the aquifer’s strength, additional energy may be provided by solution gas expansion. Much less significant contributions are provided by the expansion of the reservoir rock and its associated water. Recoveries from this type of reservoir will be the highest if the mobility of the oil is greater than that of the water.

(d)

Combination Drive Drive energy in a combination drive reservoir is provided by a combination of two or more drive mechanisms. The production trends reflect the characteristics of the dominant drive mechanism, which may change with time. The recovery may be high or low, depending on which drive mechanisms dominate.

(e)

Gravity Drainage Gravity drainage, which is a special case of combination drive, is a driving force created by the density difference between oil and gas, causing a downward flow of oil. Gravity drainage occurs only in combination with one or more of the primary oil reservoir drive mechanisms and typically occurs in steeply dipping reservoirs. Gravity drainage is a secondary drive mechanism usually associated with an expanding primary or secondary gas cap. Gravity drainage reservoir performance depends on the maximum gravity drainage rate and is reflected in the reservoir pressure, GOR, and recovery trends. The primary disadvantage of gravity drainage is that the oil is recovered over a long time. Ultimate recovery from gravity drainage reservoirs varies depending on the fraction of the recovery attributable to gravity drainage.

CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Figure (1.1) illustrates the reservoir performance for the three major primary drive mechanisms. 100 5

Water Drive

Gas Oil Ratio (GOR) - MCF / BBL

Reservoir Pressure - % of Original

Gas Cap Drive

80

60

Gas Cap Drive 40

20

Solution Gas Drive 10

20

4

3

2

1

Water Drive

0

0 0

Solution Gas Drive

30

40

50

60

Oil Produced - % of Oil initially in place

70

80

0

10

20

30

40

50

60

70

80

Oil Produced - % of Oil initially in place

Figure (1.1) (a) Reservoir Pressure Trends (b) GOR Trends 1.4.2

Well Productivity

An oil or gas reservoir contains highly compressible hydrocarbon fluids at an elevated pressure and temperature and as such, the fluid stores up within itself considerable energy of compression. The efficient production of fluids from a reservoir requires the effective dissipation of this energy through the production system. Optimum utilisation of this energy is an essential part of a successful completion. The productivity of the system is dependent on the pressure loss, which occurs in several areas of the flow system namely:      

The reservoir The wellbore The tubing The choke The flow line The separator

The optimum distribution of energy between these various areas has a major bearing on the production effectiveness of a well completion. The selection of the appropriate completion string is fit for purpose components which will control the cost effectiveness. The pressure drop, which occurs across the reservoir, is defined as the inflow performance relationship or IPR. The pressure drop in the tubing and wellbore, post perforations, is that which occurs in lifting the fluids from the reservoir to the surface and it is known as the vertical lift performance (VLP), or the tubing performance relationship (TPR). This is a frictional pressure drop caused by the flow of fluids through the casing and production tubing to the wellhead. In addition to overcoming the frictional pressure drop it is also necessary to have sufficient energy in the reservoir fluid to overcome the hydrostatic head required for the fluid to reach the surface from reservoir depth and to maintain the stipulated wellhead pressure which is required to feed the reservoir fluids into the production phase separator at its optimum operating pressure. CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

The pressure drop across the reservoir, the tubing and in fact across the choke is rate dependant and these relationships therefore define the means by which we can optimise the production of the fluid from the reservoir. In some cases these will impose significant limitations on the extent to which we can utilise and optimise the dissipation of this energy. These are discussed below: (1)

Limited Reservoir Pressure – in cases where the reservoir pressure is limited, it may not be feasible to achieve a significant and economic production rate from the well. In such cases it may be necessary to either assist in maintaining reservoir pressure or arrest the production decline by the use of gas or water injection for re-pressurisation. Alternatively, the use of some artificial lift technique to offset some of the vertical lift pressure requirements and thus increase the production capacity of the system may be implemented. Pressure drop across the wellbore can be reduced substantially by having a horizontal section in the wellbore. This basically increases the length of formation available for production, hence increasing the productivity index, PI, of the well.

(2)

Minimum Surface Pressure – on arrival at the surface, the hydrocarbon fluids are fed down a pipeline through a choke and a production manifold to the production separator, where phase separation is allowed to take place. The production rates of oil, gas and water are measured here prior to the separate phases, oil, gas and water, being sent to various treatment facilities for further processing. To be able to allow the fluids to be driven through the initial separation process and in fact to provide some of the energy required for the process itself and to maximise the production rate, it will be necessary to have the minimum possible wellhead pressure that will be greater than the sum of the frictional pressure drop between the wellhead and the separator and the operating pressure of the separator itself (normally, 100 to 200 psig).

1.4.3

Well Completion

Historically, the major portion of production technology activities is associated with the engineering and installation of the downhole completion equipment. The completion string is a critical component of the production system and to be effective it must be efficiently designed, installed and maintained. Increasingly, with moves to higher reservoir pressures and more hostile environments, the actual capital cost of the completion string is becoming a significant proportion of the well cost and thus worthy of greater technical consideration and optimisation.

CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

The completion process can be split into several key areas, which need to be defined before the commencement of the designing process. Some of these are highlighted in the following text. The fluid, which will be used to fill the wellbore during the completion process, referred to as the completion fluid, must be identified and this requires that the function of the fluid and the required properties be specified. The completion must consider and specify how the reservoir fluids will enter the wellbore from the formation i.e., whether in fact the well will be open or whether a casing string will be run which will need to be subsequently perforated to allow a limited number of entry points for fluid to flow from the reservoir into the wellbore. This is necessary to maintain the mechanical integrity of the well. It is also possible that special sand production prevention equipment may be required as a consequence of the quality of the formation resulting in increased pressure drop across the wellbore.

Conductor Pipe

Surface Casing

Production Casing

Production Tubing Protective Casing Liner

a. Hydro-Pressured Wells

b. Geo-Pressured Wells

Figure (1.2) Typical Casing Configurations

The design of the completion string itself must provide the required containment capability to allow fluids to flow safely to the surface with minimal loss in pressure. In addition however, it is crucial that the string be able to perform several other functions, which may be related to safety, control, monitoring, etc. The completion string must consider what contingencies are available in the event of changing fluid production characteristics and how minor servicing operations could be conducted, for example, replacement of valve etc. All equipment in the wellbore and the wellhead itself must be designed to stand the operating conditions and the specified pressure ratings. CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Figure (1.2) depicts a typical casing string design and a typical well completion string is shown in Figure (1.3). A basic wellhead assembly is displayed in Figure (1.4).

Controller

Control Line

Circulating Device

Safety Valve

Production Packer Circulating Device Flow Coupling Selective Landing Nipple for Flow Control

Casing

Blast Joint Tubing

Selective Landing Nipple for Flow Controls

Production Packer Side Pocket Mandrel

Circulating Device Flow Coupling Selective Landing Nipple for Flow Controls Blast Joint Sliding Sleeve

Selective Landing Nipple for Flow controls

Hydraulic Set Packer

Production Packer No-Go Landing Nipple

Landing Nipple

PE-500 Pump Out Plug

Figure (1.3) Typical Well Completion

CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Single String Completion

Figure (1.4) Basic Wellhead Assembly 1.4.4

Well Stimulation

The productivity of a well naturally arises from the compressed state of the fluids, their mobility and the flow properties of the rock, primarily in terms of permeability. In some cases reservoirs may contain substantial reserves of hydrocarbons but the degree of inter-connection of the pore space and low permeability may substantially reduce the recovery even if sufficient natural reservoir energy is available. In such circumstances, it may be beneficial to stimulate (increase permeability) the production capacity of the well. The stimulation techniques are intended to: 

Improve the degree of inter-connection between the pores.



Remove impediments to flow, such as fines blocking the pore throats.



Provide a large conductive hydraulic channel, which will allow the wellbore to communicate with a larger conductive area of the reservoir.

In a nutshell the permeability, which is the property of the rock that dictates the ease with which a fluid can move through a porous medium, needs to be increased. In general there are three principal techniques used in well stimulation operations, namely, Fracturing, Acidisation and Acid Fracturing. Fracturing – this technique is used in very tight reservoirs where the matrix permeability is extremely low. Fractures are created in the reservoir rock by pumping fluids, quite often with propants at high pressure and high flowrate into the formation. The injection pressure at the wellbore must exceed the overburden pressure. This breaks down the reservoir rock and cracks begin to appear within the reservoir. This technique increases the effective well bore radius of the well and hence the effective permeability (Figure (1.5)). The propants are used to keep the fractures open after the pressure at surface is released at the end of the fracturing (fraccing) process. CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Vugs

Master of Petroleum / Petroleum Well Engineering Production Technology

M atrix

Fracture Fractures

Actual Reservoir

Matrix

Model Reservoir

Figure (1.5) Idealisation of a Fractured Reservoir

Acidisation – this process can be conducted at pressures either above or below the formation break down gradient (fracture gradient) and requires the injection of an acid into the reservoir to either dissolve the rock matrix and/or dissolve contaminants which have invaded the rock pore space during drilling or completion operations. The main objective of acidisation, as with all stimulation operations, is to increase the permeability of the rock. Acid Fracturing – here, the acid is injected at a pressure above the formation breakdown gradient to create a fracture while dissolving unwanted debris lodged in the pores or simply to dissolve part of the rock itself. The acid then etches flow channels on the surface of the fracture, which on closure will provide deep conductive flow channels. A number of other chemical treatments are available for specific situations. 1.4.5

Associated Production Problems

The ongoing process of hydrocarbon production from a well is a dynamic process and this is often evidenced in terms of changes in the rock or fluid production characteristics. These are frequently caused by: 

Reduction of the well productivity index, PI, due to multiphase flow. Once water breaks through into a wellbore, due to relative permeability issues the PI of the well will drop from that evidenced during a 100% (single phase) oil flow.



Physio-chemical changes may occur as produced fluids experience a reduction in the temperature and pressure as a result of flow through the reservoir and through the casing and tubing up to the wellhead. This can result in a deposition of heavy hydrocarbon materials such as asphaltenes and waxes on the wall and inside of the production tubing. This depends on the pour point of the crude oil. The higher the pour point, the greater the chance of wax deposition. Also, movement of

CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

fines within the reservoir could cause blockage of the pore throats resulting in the reduction of the permeability. 

Incompatibility between reservoir fluids and external fluids introduced into the wellbore may result in formation damage induced by scale deposits and the formation of liquid emulsions. This is a common occurrence, if not understood at the planning stages, with water-flooding operations.



Mechanical collapse or breakdown of the formation may give rise to the production of individual grains of formation sand with the produced fluids causing tubing and surface pipeline erosion and separator blockage. This is a common problem with unconsolidated formations.



Corrosion due to the inherent corrosive nature of some of the components contained in the hydrocarbon system, for example, the presence of H2S and/or CO2.



Other processing problems can be caused by the appearance of radioactive scales, foams, heavy metal deposits, etc.

1.4.6

Remedial and Workover Techniques

The production technologist is responsible for monitoring and ensuring the ongoing safe and optimal operation of all the wells under his/her jurisdiction. As such, the responsibilities include the prevention, identification and resolution of problems that may occur with the production system. This area of work is critical to the ongoing economic viability of the field and can be subdivided into a number of areas, namely: (1)

Identification of problems and their source: this is normally conducted on the basis of surface information, which indicates changes in production characteristics such as rate, pressures and increasing water/oil and gas/oil ratios. In addition, downhole investigations through well surveillance will give information on the cause of the problems. Techniques such as production logging and pressure transient testing can help to identify the location of the problems and the reasons for the changes.

(2)

Planning of the required corrective action: this requires considerable attention to detail and will necessitate: (a) Identifying the necessary equipment, manpower and other support required. (b) Identification and assessment of the unknowns / uncertainties. (c) Identification and evaluation of the key safety points and milestones.

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

(3)

The assessment of the probability of technical and economic success.

(4)

Identification of the required skilled personnel and their supervision.

(5)

Attention to detail and careful planning are essential when it is necessary to workover a well. In addition to well control and other safety aspects, one must also be careful not to inflict further damage to the well’s current productivity.

1.4.7

Surface Processing

In some cases surface processing falls within the domain of production technology but in most cases it is the responsibility of a production department involving process engineers. The surface processing operations consist of: (1)

Separation: To effectively separate oil, gas and water. This could be done by a single stage or a multi-stage process.

(2)

Dehydration: Removing water droplets or BS&W (Basic Sediments and Water) from the crude oil and gas.

(3)

Desalting: Reduction of the salt content of the crude oil by diluting the entrained/emulsified water before dehydrating.

(4)

Sweetening: Removal of H2S and other Sulphur compounds.

(5)

Stabilisation: Removal of the most volatile components of the crude oil to reduce the Reid Vapour Pressure (RVP) or if more correctly stated, the reduction of the bubble point pressure. That is, the removal of dissolved natural gas to a limit that is necessary for the crude oil to be safely transported and stored.

(6)

Water Processing: Removal of oil droplets and oil-in-water emulsions from the produced water, satisfying the threshold limits set, before disposal. The threshold limit for offshore Australia is 30 ppm oil in water.

(7)

Sand Removal: Any sand and other solids gathered in any of the processing equipment, such as the separator, production manifold and flowlines, must be removed.

The selection and operation of surface production facilities, obviously, depend very strongly on the volume processed and the characteristics of the streams being produced at the wellhead. In every situation the actual processing scheme depends not only on the wellhead stream, but also on product quality and deliverability specifications. A typical oil field processing system is shown in Figure (1.6).

CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Gas Flare System Pipeline Compression Gas Dehydration System

Gas Liquids Recovery System

Gas Lift Compression

Gas

Gathering System

Reservoir

Separation System

Oil

Gas Re-Injection

Oil Treatment System

Storage System

Pumping System

Pipeline

Tanker Water

Oil Oily-Water Separation System

Filtration System

Deaeration System

Water

Sea

Pumping System

Water Injection System

Figure (1.6) Surface Processing

1.5

The Composite Production System

The composite production system is comprised of the production casing, the subsurface well completion, the wellhead, the choke and the flowlines to the production separator, the production separation process itself and the facilities used for transferring the produced fluids to their intended destinations. 1.5.1 General Description The energy stored within the reservoir is available to cause the fluids to flow from the reservoir to the wellbore and then to the surface. The design of a producing system that efficiently uses this available energy to maximise the production from the reservoir to the wellhead is fundamental to efficient well completion design and the responsibility rests with the production technologist. During the production of oil from the reservoir to a storage tank, the oil has to flow through a variety of restrictions that will consume some of the energy stored within the compressed fluids and controlled by their pressure and temperature. The combined system of the reservoir, the wellbore and the surface treatment facilities is generally referred to as the composite production system (Figure (1.7)).

CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Well Head Choke Conductor Pipe Gas Surface Casing Tubing Oil String Oil

Packer

Water

Perforations

Casing Shoe

Figure (1.7) Composite Production System 1.5.2

Utilisation of Reservoir Pressure

In the development of a hydrocarbon reservoir, the energy stored up within the compressed state of the reservoir fluids has to, in the majority of cases, overcome the total pressure loss in the producing system. Based upon a fixed operating pressure for the separator, we can formulate the pressure loss distribution as follows: p RES  p RES  pWB  p PT  p SURF  pCHOKE  p SEP

(1.1)

where, pRES is the initial or average pressure within the well drainage area in the reservoir.

 pRES is the pressure loss caused by the flow of fluid within the reservoir to the wellbore.  pWB is the total pressure loss generated by the design of the fluid entry into the wellbore, i.e., the bottom hole completion details (perforations, gravel pack, pre-packed screens etc.).  pPT is the pressure loss caused by fluid flowing up the production tubing string.

 pSURF is the pressure loss generated in the Xmas tree, production manifold and surface flowlines. CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

 pCHOKE is the pressure loss across the choke. pSEP is the required operating pressure for the separator. The pressure drop required to bring the fluids from the wellbore to the wellhead can be calculated from the following equation: p PT  p F  p H

(1.2)

where,

pF is the frictional pressure drop in the production tubing which is a function of the fluid velocity. pH is the hydrostatic head between the wellbore and the wellhead which is dependent on the density of the fluids present in the tubing, the vertical distance between the wellbore and the wellhead and gravity. p H  hg

Equation (1.1) can be rearranged to give, ( p RES  p SEP )  p RES  pWB  p PT  p SURF  pCHOKE

(1.3)

Where, (pRES – pSEP) is the pressure drop available for the production system and hence will determine the rate at which the fluids can be produced to the surface. All the pressure drop terms in equation (1.3) are rate dependent and hence the total system pressure drop can be calculated as: pTOTAL  p RES  pWB  p PT  p SURF  pCHOKE Q

(1.4)

Thus, each of the pressure drops can be minimised either individually or collectively to give the maximum production rate for the available pressure drop. This is known as production system optimisation. The following text introduces the techniques normally used to minimise these pressure drops to provide a maximum potential production rate. To reduce the pressure loss due to flow in the reservoir, it is necessary to reduce the resistance to flow. This can be accomplished either by reducing the formation rock resistance, e.g., increasing the permeability by acidisation or fracturing or by reducing the resistance to flow due to the fluid properties, e.g., viscosity by utilising thermal recovery techniques. These alternatives are normally too costly to be readily applicable except in specific situations, e.g., chalk reservoirs or with very heavy crude oil reservoirs and may involve considerable technical risk. CHAPTER 1 Introduction

Page 1-17

Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

The pressure loss due to the bottom hole completion method has to be specified as part of the completion design and, as such, is a major area for production optimisation. It is likely that detailed consideration given to some aspects in this area such as perforation shot density and length of perforated interval could be very beneficial to maximising the production capacity of the system. Consideration must also be given to the possible use of a horizontal well instead of a vertical or a deviated well. In some cases, multi-lateral wells may be looked at. Again, as with the bottom hole completion pressure loss, the vertical lift pressure loss in the production tubing is a major area for optimisation, as not only does the engineer have to specify the length and diameters of all sections of the tubing string but also all the specific completion components used in the string. Careful design in this area should provide significant productive capacity. The surface flowline pressure loss is relatively less important in that it is easily controllable even after the event. The diameter of the flowlines can be increased to compensate for the number of bends and valves used in the system. Also, the length of the flowline can be shortened through innovative facilities design of the surface production facilities and layout. Even if mistakes were made during the initial design, facilities can be upgraded without having to outlay too much capital. Little flexibility exists to minimise choke size as it is required to give a specific pressure drop for a known flowrate to provide stability to the production separator. 1.6

Supplementing Reservoir Energy

The effective utilisation of reservoir energy with respect to reservoir production system optimisation was covered elsewhere in the course. It is clear that the increased production rate could be attained by supplementing the natural reservoir energy through either; (a)

Increasing the reservoir pressure.

(b)

Providing more energy for the vertical lift process.

or

Increasing the reservoir pressure above its initial value is difficult to conceive for two reasons: (1)

In any reservoir development, to achieve any noticeable increase in reservoir pressure would require fluid to be injected into the reservoir over a considerable period of time and this would normally preclude any significant production taking place in view of the consequent depletion of the hydrocarbon volume and pressure which would be associated with it.

CHAPTER 1 Introduction

Page 1-18

Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Firstly, the oil has to flow through the reservoir rock to reach the wellbore and, in doing so, a loss in pressure will occur within the reservoir and across the wellbore. The pressure drop across the wellbore, commonly referred to as the “drawdown”, is principally dependent upon the reservoir rock and fluid characteristics. Once inside the wellbore, the fluid has to flow up the production tubing string passing through various sizes of tubing and through restrictions caused by other completion string components. This pressure loss comprises three principal sources of pressure loss, namely: Frictional pressure loss, i.e., loss associated with viscous drag and proportional to the fluid velocity. Hydrostatic head pressure loss due to the density of the fluid column in the production tubing. A kinetic energy loss due to expansion and contraction in the fluid flow area and the associated acceleration/deceleration of the fluid as it flows through various restrictions. The sum of these three pressure losses is termed the vertical lift pressure loss. It is possible to separate the pressure losses due to individual tubing components, such as downhole valves, from the total vertical lift pressure loss to allow optimisation in terms of specific component sizing. When the fluid arrives at the surface, it passes through the surface equipment and flowline, giving rise to further pressure losses. The fluid will then have to pass through the choke into the production separator. The choke is designed to cause a significant amount of pressure drop to provide stability to downstream separation operations. The separator is designed to separate out the liquid and gas phases continuously to provide produced gas and oil for shipment and water for disposal. The separator is maintained at its optimum operating pressure. (2)

The volume of fluid to be injected into the reservoir to provide an increase in pressure would be dependent upon the overall compressibility of the reservoir rock and the fluid system. For reservoirs of commercial size, the volume of fluid would be considerable and may be uneconomic depending on the properties of the oil. In a reservoir with an ideal mobility ratio of M =< 1, the injection water requirement will be minimal, however, if M > 1, many pore volumes of water will have to be injected because of very high surface water production. In such situations, the alternative methods available may need to be applied to increase fluid production rates.

CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

1.6.1

Master of Petroleum / Petroleum Well Engineering Production Technology

Fluid Injection into the Reservoir

The potential use of fluid injection into the reservoir to arrest reservoir pressure decline will help maintain the desired production rates and could improve oil recovery through immiscible displacement. From the material balance concept applied to hydrocarbon reservoirs, it is clear that unless the underground fluid withdrawal from the reservoir can be compensated for by an equal volume of fluid flow into the reservoir from, say, a very large aquifer or another external source, then the reservoir pressure will fall. When the average pressure in the reservoir declines, then the available energy for production declines and as a result the oil production rate will drop.

AVERAGE RESERVOIR PRESSURE - psia

Thus, the principal application of fluid injection into the reservoir is to try and balance the reservoir underground fluid volume withdrawn to that injected to maintain reservoir pressure. If this is accomplished, it will not increase the maximum production rate attainable but it will restrict the rate of production decline. Also through immiscible displacement under favourable conditions this will increase the recovery of oil. Figure (1.8) illustrates the benefits of water injection. pavg

3000

With Water Injection

2500

Cumulative Oil Production with Water Injection

No Water Injection

2000

Cumulative Oil Production without Water Injection

1500

1000

0

1

2

3

4

5

6

7

8

TIME - YEARS

Figure (1.8) Benefit of Water Injection – Sustain Natural Production

The decision as to whether water or gas should be injected is influenced by fluid availability and characteristics. Water injection is of particular importance since water is usually available either as produced water or seawater in an offshore situation or from another formation, preferably, deeper in the vicinity of the oil-producing reservoir. If surface water is used, then it needs to be treated and pumped. Water is, however, only slightly compressible and as such is not an ideal fluid for compression energy storage, but alternatively, compression costs are low. Injection of water can improve oil recovery dramatically through displacement if the oil’s mobility is greater than that of the water. CHAPTER 1 Introduction

Page 1-20

Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Gas, however, is more compressible and hence more suitable as an injected fluid for pressure maintenance, however, it requires considerable compression to allow its injection into the reservoir. Furthermore, gas injection can cause premature free gas breakthrough and reduce oil recovery. The supply of gas would be a predominant factor when deciding to use gas injection as a means for pressure maintenance. In most cases its commercial value is of primary importance and this might preclude its use for reinjection unless no means of export is available as flaring is prohibited in most countries. Either way, if gas is produced in large quantities and there is minimal aquifer support, the gas should be reinjected into the reservoir to preserve energy. A schematic of a water injection set up is shown in Figure (1.9).

Scale Inhibitor

Bacteriocide

Pump

Filtration

Deaeration

Holding Tank

Corrosion Inhibitor

Pump

Formation

Seawater

Figure (1.9) Typical Injection Water Treatment Facility

1.6.2

Supplementing the Vertical Lift Process

There are several methods available to assist in lifting the produced liquids to the surface and these are collectively referred to as Artificial Lift Techniques. These processes are widely applied worldwide in enhancing oil production rates. In some cases, they are essential to the initial economic development of a hydrocarbon reservoir whilst in other cases they are implemented later in the life of the field to maintain production at economic levels. This might be necessitated by high water production or declining reservoir pressure in a solution gas drive reservoir. The various techniques can be further classified into those which simply provide additional energy to assist the lift process, and those that provide some reduction in the vertical lift pressure gradient through fluid density reduction. Some of the artificial lift techniques applied in the oil industry are explored below.

CHAPTER 1 Introduction

Page 1-21

Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

1. Gas Lift The gas lift process involves the injection of gas normally into the annulus between the production tubing and the casing. The injected gas is subsequently allowed to enter the flowstream within the production tubing at some specific depth (Figure (1.10)) through a gas lift (injection) valve. The injection of gas into the production tubing provides a stepwise increase in the gas liquid ratio of the fluids flowing in the tubing at that depth and throughout the tubing above the injection point up to the wellhead. To be able to enter the tubing, the pressure of the gas in the annulus at the valve depth must be greater than the pressure of the fluids in the tubing at the corresponding depth. A gas lift set up is shown in Figure (1.10). Oil level has moved downwards, each valve has closed as gas entered next lower valve.

Oil and Gas

Surface

Oil and gas

Gas Gas Oil level Tubing Gas-lift valves

1st valve open gas entering tubing oil level in casing/tubing annulus moving downwards

Gas entering foot of tubing

Casing

Oil (a) Well dead

(b) Commencing gas lift

(c) Normal gas lift

Producing formation

Figure (1.10) Gas Lifted Well

By injecting gas, the Gas Liquid Ratio (GLR) of the flowing fluid is increased, i.e., its effective flowing density is reduced and hence, the hydrostatic head is lowered. As a consequence, the bottomhole flowing pressure is reduced and hence the production rate is increased as long as the PI does not change. The compressibility of the gas will assist in the lift process. However, as the gas rises up with the liquid it will expand causing an increase in the frictional pressure losses negating some of the advantage gained through the reduced hydrostatic head. With increasing gas injection volume, the hydrostatic head will continue to decline but the benefits in reduced density may incrementally be eroded, whilst the additional frictional pressure loss caused by gas expansion continues to increase. Therefore, an optimum gas injection rate will need to be selected for the specific situation. This requires the estimation of the optimum gas injection rate and the positioning of the gas lift valve at the correct depth. Multiple gas injection valves can also be used.

CHAPTER 1 Introduction

Page 1-22

Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Gas lift is a very effective method of increasing the production rate, provided that the gas is efficiently dispersed within the flowing fluid column and the optimum injection rate is not exceeded. It is also cheaper than all the other available lift techniques and has no moving parts in the equipment used downstream of the compressor and hence the production downtime is minimal. 2. Downhole Pumping Referring to equation (1.1), if a pump system is used, then an additional term is introduced to reflect the supplementary energy provided by the pump,  ppump, which will allow a higher production rate to be attained:

p RES  p pump  p RES  pWB  p PT  p SURF  pCHOKE  p SEP

(1.5)

There are four principal methods available for pumping as follows: (a) Electric Submersible Pumps (ESP) This consists of a multi stage centrifugal pump located at some position downhole as an integral part of the tubing string (Figure (1.11)). The ESP consists of three major components, namely, the multi-stage centrifugal pump at the top of the pump assembly, the seal section in the middle and the pump electric motor at the base. The requirement for the pump suction to be flooded with liquid will dictate the pump setting depth in the well. The liquid level in the well, however, will be dependent on the reservoir pressure. An electric cable installed on the outside of the production tubing supplies the power from surface to the downhole motor. This type of pump is ideally suited for high rate production and in low permeability reservoirs. In situations where there is an appreciable amount of free gas produced, downhole gas-liquid separation equipment will need to be considered, otherwise the pump will cavitate. The ESPs can be installed to run at a fixed speed or, with the use of a Variable Speed Drive (VSD), the pump can be run at variable speeds.

CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Figure (1.11) Electric Submersible Pump Assembly

(b) Hydraulic Downhole Pumps This type of pump is again run at the tail end of the tubing string and it normally utilises hydraulic fluid power fed down a separate small bore tubing parallel to the tubing string (Figure (1.12)). Alternatively, the fluid can be injected via the casing tubing annulus. Fluid pumped down the line at high pressure powers the drive unit of the downhole pump. The hydraulic fluid then joins the flowing well fluid in the tubing and returns to surface. CHAPTER 1 Introduction

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Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Figure (1.12) Downhole Hydraulic Pump Assembly (Kermit Brown, Vol 2a – p359)

(c) Sucker Rod Pumping In this system, a plunger, cylinder and a standing valve system are located downhole as part of the tubing string and connected by steel rods to a vertical reciprocation system at surface (Figure (1.13)). The surface reciprocation system is referred to as a “nodding donkey”. This type of system is suitable for very low to medium production rates.

CHAPTER 1 Introduction

Page 1-25

Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Figure (1.13) Sucker Rod Pump Assembly

(d) Jet Pumping The subsurface jet pumps are a special class of hydraulic pumps but with no moving parts in the assembly. In jet pumping (Figure (1.14)), the power fluid (oil or water) is pumped down the tubing/casing annulus to the fluid entry point. The power fluid thus entering the jet pump is allowed to expand through an orifice that, using the venturi concept, creates suction at the base of the pump. This suction allows the reservoir fluids to enter the pump and both the power and the reservoir fluids are pumped to the surface. This is achieved through momentum transfer between the power fluid and the produced fluid.

CHAPTER 1 Introduction

Page 1-26

Curtin University of Technology Department of Petroleum Engineering

Master of Petroleum / Petroleum Well Engineering Production Technology

Figure (1.14) Type A - Jet Pump (Kermit Brown, Vol 2a – p453)

Several other pumping systems are available in the market. The type of artificial lift system selected will be dependent on the well requirement and capabilities and the availability of the resources to drive the pump lift mechanisms such as, electricity, gas, power fluids etc.

CHAPTER 1 Introduction

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