Overview of Oil & Gas Production System Components and Operations

PRODUCTION

CONTENTS Introduction Production System Inflow Performance Relationship Gas Deliverability testing Tubing Performance Relationship References

INTRODUCTION In the petroleum industry, production is the phase of operation that deals with bringing well fluids to the surface and preparing them for their trip to the refinery or processing plant. Production begins after drilling is finished.

CONTINUED…  Production is a combination of operations: bringing fluids to the surface • doing whatever is necessary to keep the well producing • and taking fluids through a series of steps to purify, measure, and • test them

Production System A complete oil or gas production system consists of:  Reservoir  Wellhead  Production Tubing  Flowlines  Separators  Pumps  Transportation Pipelines

Production System

Reservoir A reservoir is a porous and permeable underground formation containing an individual bank of hydrocarbons confined by impermeable rock or water barriers and is characterized by a single natural pressure system.

Types of Reservoir Depending on the initial reservoir condition in the phase diagram, hydrocarbon accumulations are classified as  Oil  Gas condensate  Gas reservoirs

CONTINUED…  Undersaturated Oil An oil that is at a pressure above its bubble-point pressure is called an Undersaturated oil because it can dissolve more gas at the given temperature. • Single (liquid)-phase flow prevails in an undersaturated oil reservoir. •  Saturated Oil An oil that is at its bubble-point pressure is called a ‘‘saturated oil’’ because it can dissolve no more gas at the given temperature. • Two-phase (liquid oil and free gas) flow exists in a saturated oil reservoir. •

Types of Wells Depending on the producing gas–oil ratio (GOR) wells in the same reservoir can fall into categories of: Oil  Those with producing GOR being less than 5,000 scf/stb Condensate  Those with producing GOR being less than 100,000 scf/stb but greater than 5,000 scf/stb  Gas wells  Those with producing GOR being greater than 100,000 scf/stb

Wellhead A wellhead is the component at the surface of an oil or gas well that provides the structural and pressure-containing interface for the drilling and production equipment.

CONTINUED… Wellheads are typically welded onto the first string of casing, which has been cemented in place during drilling operations, to form an integral structure of the well. In exploration wells that are later abandoned, the wellhead may be recovered for refurbishment and re-use. Offshore, where a wellhead is located on the production platform it is called a surface wellhead, and if located beneath the water then it is referred to as a subsea wellhead or mudline wellhead.

Functions of Wellhead  The primary purpose of a wellhead is to provide the suspension point and pressure seals for the casing strings that run from the bottom of the hole sections to the surface pressure control equipment.  Provide a means of casing suspension. (Casing is the permanently installed pipe used to line the well hole for pressure containment and collapse prevention during the drilling phase).  Provides a means of tubing suspension. (Tubing is removable pipe installed in the well through which well fluids pass).  Provides a means of pressure sealing and isolation between casing at surface when many casing strings are used.

CONTINUED…  Provides pressure monitoring and pumping access to annuli between the different casing/tubing strings.  Provides a means of attaching a blowout preventer during drilling.  Provides a means of attaching a Christmas tree for production operations.  Provides a reliable means of well access.  Provides a means of attaching a well pump

Wellhead Components The primary components of a wellhead system are: 7. Mudline suspension systems 1. Casing head 2. Casing spools 8. Tubing heads 3. Casing hangers 9. Tubing hangers 4. Choke manifold 10. Tubing head adapter 5. Packoffs (isolation) seals 6. Test plugs

Wellhead Components

Casing Head The casing head is the part of wellhead assembly and is almost always connected to surface wellhead string. It supports the subsequent parts of the wellhead and completion equipment.

Casing Head

CHRISTMES TREE

Production Tubing Production tubing passes through the wellbore up to the reservoir and is responsible for transporting the reservoir fluids to surface. • While selecting production tubing, the wellbore geometry, properties of reservoir fluids and production characteristics of the concerned reservoir have to be considered. • Production tubing along with other completion components such as casing makes up the production string.

CONTINUED… Production tubing protects wellbore casing from 1. Wear and tear 2. Corrosion 3. Deposition of by-products, such as sand / silt, paraffins, and asphaltenes

Completion Jewelry TUBING HANGER: To anchor the tubing string, a device is mounted to the wellhead's topmost tubing joint. The tubing hanger is typically located inside the tubing head, and both components are equipped with a sealing mechanism to keep the tubing conduit and annulus hydraulically isolated.

Completion Jewelry PUP JOINT: Pup joint is defined as a tubing string (shorter than normal) to compensate for the length of the overall production string. They are also known as saver sub, spacer and pup.

Completion Jewelry CROSSOVER: A short subassembly used to enable two components with different thread types or sizes to be connected.

CONTROL LINE FOR SC-SSSV: It is used to depressurize/pressurize the SCSSSV from the surface so it may close/open depending upon the fail-close/fail-open mechanism. A 1/4-inch stainless steel control line is attached to the outside of the tubing string and placed when the tubing is installed with SCSSV. Depending on the wellhead pressure, it may be necessary to maintain a pressure on the control line of 4000 to 5000 psi to keep the valve open. Pressure drop over a flow bean is sensed by the differential type subsurface controlled subsurface safety valve. SSCSV is a differential type with various versions. Flow beans and spring tension regulate all of them, even if they use different sealing methods like a flapper or a ball.

FLOW COUPLING: Thick-walled diameter component to cater for the effects of wearing and tearing due to turbulence when flow passes through smaller diameter. There are two flow couplings, one for the production and one for the potential injection purposes. They are typically used in the production tubing where velocity is subjected to some changes owing to changes in diameter of tubing. In a nutshell, it is used to increase the life of well by catering for erosional effects both internally and externally.

TUBING RETRIEVABLE SCSSSV: SCSSSV is an emergency shutdown of the well to cater for the disastrous moments when there is no-one to shut down the well. It is tubing retrievable i.e., tubing has to be removed to replace or remove it, in our case but in the following text, there are others In the event that surface controls fail or surface equipment is damaged, safety valves are designed to immediately shut off the flow of a well. They are classified based on whether they are regulated from the surface or the subsurface.

All wells capable of natural flow to the surface should have a secondary means of closure, which is usually required. This emergency closing capability will be provided by the installation of a sub-surface safety valve (SSSV). The following text discusses subsurface safety valve types, operating systems, functioning principle, setting depth, and selection method. Based on the retrieving mechanism, there are two types of SSSV Tubing Conveyed • Wireline Conveyed •

Operating systems Safety valves: Operating systems can be surface controlled (SCSSV), which is actuated from a control panel on the surface, or subsurface controlled (SSCSV), which is designed to close automatically when a predetermined flow condition in the well occurs (actuated by the pressure differential/flow velocity across the valve).

Working Principle: The failsafe mechanism can be used to describe the working principle. When hydraulic pressure is supplied to a control line, a sleeve within the valve is forced downwards. This action compresses a big spring, which opens the valve by pushing the flapper (in the case of flapper type SCSSV) or the ball (in the case of ball type SCSSV) downwards. When hydraulic pressure is released, the spring returns the sleeve to its original position, causing the flapper (or ball) to close. In this way, it is failsafe, isolating the wellbore in the case of a wellhead failure.

GAS LIFT MANDREL: It is used to add energy to the fluid and lift the liquid up to the surface i.e., gas injection These can be categorized into two: 1. Traditional Mandrel 2. Side-Pocket. Mandrel Valves must be fitted in mandrels on the surface and run with the tubing in traditional mandrels. Side-pocket mandrels are designed to allow wireline installation of valves and other downhole components.

PACKER: A packer is a well barrier element that protects the casing and creates an A-annulus in many completions. It is a sealing mechanism that isolates and contains generated fluids and pressures within the tubing string; it is usually part of the well's primary well barrier.

Packer's other functions, in addition to establishing a seal between the tubing and the casing, are as follows: Prevent tubing string movement downhole, which would result in significant axial tension or compression pressures • on the tubing string. Where there is a substantial compressive load on the tubing string, support some of the tubing's weight. • Allows for the optimal well flow conduit (tubing string) size to meet the intended production or injection flowrates. • Protect the production casing (inner casing string) from corrosion and high pressures caused by produced fluids. • Can be used to create a barrier between different producing zones. • Well control is focused on the tubing flow, allowing the downhole safety valve to shut-off flow from the reservoir, as • long as the tubing string and packer retain integrity.

Production packers can be classified into two groups: 1. Retrievable 2. Permanent

Permanent packers Permanent packers can be removed from the wellbore only by milling. The retrievable packer may or may not be resettable, but removal from the wellbore normally does not require milling. Retrieval is usually accomplished by some form of tubing manipulation. This may necessitate rotation or require pulling tension on the tubing string. Retrievable Packers: In low pressure/low temperature (LP/LT) applications, the retrievable packer can be extremely simple, whereas in high pressure/high temperature (HP/HT) applications, it can be highly complex. A retrievable packer with performance levels comparable to those of a permanent packer will necessarily cost more due to the design complexity of high-end equipment. However, the ease with which the packer may be removed from the wellbore, as well as characteristics like resettability and the ability to reuse the packer multiple times, may justify the additional expense.

Production Optimization Production Optimization refers to the various activities of measuring, analyzing, modelling, prioritizing and implementing actions to enhance productivity of a field: reservoir/well/surface. Production Optimization is a fundamental practice to ensure recovery of developed reserves while maximizing returns. Production optimization includes a good understanding about Production Systems. Production Systems includes • Reservoir (Inflow Performance Relationship) • Wellbore (Completions, Tubing etc) • Surface Facilities (Flow lines, Separator, Pipelines,etc )

Inflow Performance Relationship (IPR Inflow Performance Relationship (IPR) ) Inflow Performance Relationship (IPR) Inflow Performance Relationship is the quantification of relationship involving the bottom hole flowing pressure and flowrate. Determination of inflow performance relationship is necessary part of reservoir and production engineering which may help in a decisive way to determine ultimate fate of the field.

CONTINUED… Things are pretty different for oil wells as compared to gas wells. For oil wells, well’s productivity is a function of many parameters including water conning or gas conning breakthrough of water or gas into well which may temper sweep efficiency as they are the driving forces in case of oil wells.

Some well-known basic researchers’ methods are as follows • Vogel’s Method (1968) • Standing’s Method (1971) Fetkovich’s Method (1973) • Bandakhlia and Aziz’s Method (1989) • • Zhang’s Method (1992) Retnanto & Economides’ Method (1998) •

Vogel’s Method Vogel’s Method Vogel’s Method In 1968, Vogel presented an equation based on the about 21 random reservoir conditions was presented as follows 2 = 1 − 0.2??? ??? ?? ?? − 0.8 ???? ?? The proposed method was presented for its use in the dissolved-gas reservoir but it was found that any reservoir with the gas-saturation increasing with its pressure depletion can fall in the category of the equation. Vogel used dimensionless parameters for the IPR plotting. It has been found that the shape for inflow performance relationship is generic and is same for every reservoir.

Limitations of Vogel’s Method Vogel’s Method has the following limitations • Circular Drainage Area • Uniform Permeability • Consistent Water Saturation • No gravitational or compressibility effects • No Skin

Initially, only saturated reservoirs were being dealt by it but later some modifications were proposed to cater the undersaturated reservoirs as well. Mathematical modifications are made as the text of the project flows. For the reservoir pressure less than the bubble point pressure or at the bubble point pressure, following combination of formulae are used 2 = 1 − 0.2??? ??? ?? ?? − 0.8 ???? ?? It can be written as follows 2 1 − 0.2??? ??? ?? ??= ???? − 0.8 ?? ????= ??? 1.8

Or to estimate the bottomhole pressure using the flowrates, it can be estimated as follows ? ???= 0.125? 81 − 80 − 1 ???? J can be determined as follows ?? ???? ?? = ? = ??− ??? ???? Or J may be calculated using Darcy’s Law ?ℎ ? = 141.2???? ln?? ??−3 4+ ?

If the reservoir is undersaturated, then there are the following conditions At ???> ?? ? = ? ??− ??? When ???= ?? ??= ? ??− ?? When ???< ?? 2 ??? ?? ??? ?? ??= ??+ ????− ?? 1 − 0.2 − 0.8

Or it can be written as ????=??? 1.8+ ?? 2 ??? ?? ??? ?? ??= ??+??? 1 − 0.2 − 0.8 1.8 If test was conducted below bubble point i.e., bottomhole flowing pressure is less than bubble point pressure, then the productivity index can be estimated from the following correlation ?? ???? ??? ???? ?? ? = 2 ??? ???? ?? (??−??) +?? 1 − 0.2 − 0.8 1.8

Standing’s Standing’s Method Method Standing’s Method Vogel’s method was only applicable for the reservoirs with zero skin factor, which dictates the ideal conditions. These ideal conditions do not follow in real world. Therefore, Standing, in 1971, extended the work of Vogel to cater the damage around the wellbore. He introduced a factor known as flow efficiency to describe the relationship between ideally flowing well and naturally flowing-damaged well

∆?????? ∆??????? ???? ?????????? = ?? =??− ???′ ??− ??? ?? =??− ???+ ∆????? ??− ??? Or it may be written as follows ?? =??/?′ ??/?=? ?′=??????? ??????

?ℎ 141.2???(ln?? ??−3 ?ℎ ??−3 4+ ?) ?? =??????? = ?????? 141.2???(ln?? 4) ln?? ??−3 ??−3 4 ?? = ln?? 4+ ?

Overview of Oil & Gas Production System Components and Operations