Lesson 7: Production Engineering: Well Intervention

The links below provide an outline of the material for this lesson. Be sure to carefully read through the entire lesson before returning to Canvas to submit your assignments.

7.0: Lesson Overview

In this lesson, we will discuss the design of oil and gas wells. As we have discussed in earlier lessons, Production Engineers are concerned with optimizing production from a given well. To achieve this, production engineers are the key architects of well design. In this lesson, we will discuss several important aspects of well design considered by the production engineer. These well design aspects include:

well orientation
completion design
well stimulation
artificial lift

We will see that two of the main tools used in the well design have already been discussed in this course:

The Inflow Performance Relationships, IPR (Lesson 4 and Lesson 5)
The Tubing Performance Curves, TPC (Lesson 6)

While the initial well design is the design that the well will use for the majority of its productive life, it may change over the life of the reservoir. Routine modifications to the well in response to changing well or reservoir conditions are referred to as Well Interventions or Workovers. Modifications to the well design may also be proactive, such a well recompletion, in advance of a change in the reservoir management strategy for the reservoir or field.

Many of the design aspects of the well, such as well stimulation or artificial lift, can be included in the initial well design or may be applied later in the life of the well as part of a workover.

Learning Objectives

By the end of this lesson, you should be able to:

list and understand the overriding well considerations of well design;
describe several of the more common well objectives of a well design;
discuss important well components in well design and how production engineers use the components to address the overriding well considerations and well objectives;
list and explain the different well orientations used in the oil and gas industry and discuss some of the common applications of these well orientations;
discuss the need for sand control in wells and what components of the well are used to address sand control;
list and discuss the mechanisms of unwanted fluid production from a well;
discuss the need for zonal isolation in wells and what components of the well are used to address zonal isolation;
explain the role of the well completion in a well;
list and discuss common pieces of well equipment and their uses in a well completion;
describe the role of production tubing in a well;
discuss how to determine the appropriate size of the production tubing for a well;
explain the significance of the Inflow Performance Relationship and Tubing Performance Curve in well design;
explain the need and role of well stimulation in well design; and
explain the need and role of artificial lift in well design.

Lesson 7 Checklist

Checklist
To Read	Read the Lesson 7 online material	Click the Introduction link below to continue reading the Lesson 7 material
To Do	Lesson 7 Quiz	Take the Lesson 7 Quiz in Canvas

Please refer to the Calendar in Canvas for specific time frames and due dates.

Questions?

If you have questions, please feel free to post them to the Course Q&A Discussion Board in Canvas. While you are there, feel free to post your own responses if you, too, are able to help a classmate.

7.1: Introduction

In this lesson, we will discuss several tasks performed by production engineers. In particular, we will discuss well designs, artificial lift, well stimulation, and well interventions. Most fields and reservoirs are developed by Asset Teams composed of Development Geologists, Drilling Engineers, Production Engineers, and Reservoir Engineers. The responsibilities of each team member often overlap those from other disciplines; however, the tasks listed above are predominantly carried out by the production engineer.

To illustrate the overlap, the overall field development strategy is developed by the team based on their own knowledge and skills. Based on the anticipate geology, the development geologist and production engineer will design the well. This well design includes the completion design and the tubing size (the completion is the portion of the well that connects the well tubing to the reservoir). As we will see, the completion design is heavily influenced by the geology of the reservoir. The implementation of the completion design is performed by the drilling engineer and the production engineer.

7.2: Well Design

The overriding well design considerations are:

well costs;
tubing and completion longevity;
well simplicity and reliability;
ability to achieve all (or most) of the objectives of the well.

As in all industries, the oil and gas industry is focused on keeping expenses as low as possible. This is true for well designs which are planned to be as low cost as possible while retaining the ability to keep the well safe for people and the environment. One important aspect of low costs is the longevity, or life span, of the well and completion. While changing tubulars and well completions is a common practice in the oil and gas industry; multiple, frequent changes goes against the concept of low costs.

Two aspects of the well design that lead to a longer life span are the durability of the equipment and the flexibility of the well to handle changing reservoir conditions. As we have seen in earlier lessons, these changing reservoir conditions include lower pressures caused by fluid production, lower production rates caused by the lower pressures, and changing Gas-Oil Ratios (GOR) and Watercuts ( $f_{w}$ ) over the life of the reservoir. Flexibility in well design includes the ability of the original design to handle all of the anticipated reservoir changes or, if this is not possible, designing the original completion to be able to be modified to handle these changes at the lowest possible costs.

Finally, the well must be able achieve the objectives of the well. There are many objectives other than oil or gas production that can be designed into the well. These include:

sand control for reservoirs made up of unconsolidated reservoir rock or rock susceptible to Fines Movement (movement of fine-grained materials within the rock);
zonal isolation for reservoirs with multiple zones (to allow each individual zone to be shut in, if required);
well stimulation for reservoirs with low permeability or susceptible to well damage; and
artificial lift for low rate wells.

7.3: Well Design Considerations

The main well consideration is the anticipated production rate from the reservoir. As we saw in the previous lesson, the pressure drop for a given tubing size is directly related to the production rate (or rates for multi-phase flow). For a naturally flowing well, the reservoir pressure must be great enough to lift the reservoir fluids up the well and deliver these fluids to the surface facilities. Therefore, the producing rate needs to be considered in the sizing of the tubing.

For the same reasons, the current and future reservoir pressures must also be considered in the well design. It is this pressure that drives the fluids to the production facilities. If the pressure has dropped too low due to fluid production, then artificial lift (gas lift or pumps) may be required.

The geology of the reservoir is also of vital importance in the well design. As we will see, reservoirs consisting of a single zone (or reservoir layer) may have one type of completion, while reservoirs comprised of multiple zones may require more complex completions. Typically, we would like to be able to isolate individual zones (or groups of zones) at some future point in time if required. This would occur if the reservoir conditions in some zones change at a different rate than in other zones. For example, if a well is originally producing at a low watercut, $f_{W}$ , and at some future date, one layer begins to produce water at a higher watercut than the other reservoir layers, then, we would want to be able to isolate this high watercut zone (to shut it in), while continuing to produce from the low watercut zones. We will see that some well completions will allow us to provide this ability for zonal isolation, while others will not.

In addition, as mentioned earlier, if the reservoir rock is comprised of unconsolidated rock or rock susceptible to fines migration, then we will need to design wells and completions that allow for sand control. If sand or fines enter the well, they will settle at the bottom of the well and may eventually result in Sand Fill: sand or rock material accumulating in the well and covering some or all of the well perforations.

Also, if the reservoir rock is low permeability, then we may need to consider stimulating the well in our original completion design. This how we produce gas in unconventional gas wells, such as Marcellus Shale wells in Western Pennsylvania. Figure 7.01 illustrates a typical well completion for a Marcellus Shale well.

Figure 7.01: Typical Well Design for a Marcellus Shale Well

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

In this completion design, a long horizontal well is stimulated with multiple hydraulic fractures. The need for this type of completion is because of the ultra-low permeabilities in shale reservoirs. Shale permeabilities, including the Marcellus Shale, range from nano-Darcies (10^-9 Darcies) to micro-Darcies (10^-6 Darcies). These orders of magnitude are in contrast to the milli-Darcies, md, (10^-3 Darcies) that we typically deal with in the oil and gas industry. The reason that the Marcellus Shale has opened up in the last two decades is because of completions like that shown in Figure 7.01 and the technologies behind these completions.

In addition, deep wells will inevitably encounter high pressures and temperatures and often encounter high concentrations of Acid (Corrosive) Gases, hydrogen-sulfide, H₂S, and carbon-dioxide, CO₂. In addition to being a very corrosive gas, H₂S, is highly toxic. The high pressures and temperatures require all downhole equipment be certified for those conditions. All well tubulars in highly corrosive environments require special CRA (Corrosive Resistant Alloys) steel.

In earlier lessons, we discussed the drive mechanisms in oil reservoirs. These drive mechanisms may have some significance in the types of well completions used in the reservoir. The natural drive mechanisms for oil reservoirs encountered during Primary Production (the first stage of oil production) are:

rock and fluid expansion
solution gas drive
gas cap drive
gravity drainage
natural aquifer drive (or water encroachment)

From this list, two of the drive mechanisms, solution gas drive and gas cap drive, are drive mechanisms that are due to the presence of a free gas phase. If this free gas results in high producing GORs, then the well completion must be capable of handling this gas or capable of isolating the reservoir zones containing the free gas. Likewise, the natural aquifer drive may result in mobile water in the reservoir and excessive water production with high watercuts. Again, the well completion must be designed to be able to isolate this water production.

During Secondary Production (a second stage of oil production), we may inject gas or water into the reservoir to displace oil towards the production wells. In these cases, we will need totally different well designs for our injection wells than we would use for our production wells. In addition, since we are adding these external fluids into the reservoir, we must plan our production wells to eventually produce some of these fluids. For example, if we are injecting water, even if our original well and completion design allows for zonal isolation, we will eventually start producing this water. As we saw in Lesson 6, the presence of water in the produced fluids will result in a heavier well stream, and we may need to consider artificial lift (gas lift or pump) for our production wells. As a second example, if we inject steam to improve recovery of high viscosity oils, then all of our downhole equipment must be certified for production at these elevated reservoir temperatures.

As we can see, there are many possible situations that can be encountered by a single well and infinitely more combinations of these situations. Therefore, there is no “cookbook” for well design. The best advice that I can give is to let the nature of the problem dictate the nature of solution. We can go over several common situations and example completion and well designs used in these situations.

In this lesson, we will discuss the following aspects of well design:

well orientation
completion design
tubing size
artificial lift
well stimulation

7.4: Well Orientation

We will start our discussion on well design by discussing the well orientation. In past lessons, we discussed three of the more common designs: vertical, deviated, and horizontal. These will be the well orientations that we will focus on. There are shown in Figure 7.02.

Three common well types: a vertical well drilled straight dow, a deviated well that starts straight down then deflects at a different angle, and a horizontal well that begins vertically and then turns 90 degrees and continues horizontally.

Figure 7.02: Typical Well Orientations used in the Oil and Gas Industry

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

There are many other well orientations and configurations that are possible. One broad category of these more complex wells is the category of Multi-Lateral Wells. A small subset of possible multi-lateral wells is shown in Figure 7.03. Using the naming convention in Figure 7.03, a horizontal well would be called a Single-Lateral Well. The term Lateral refers to the number of horizontal branches emanating from a single vertical well section.

Historically, the most common on-shore wells have been vertical wells. This is because of their simplicity and economics. It turns out that straight vertical wells are the most economic wells that can be drilled. Rigs are contracted on a daily basis, and the fastest way to drill a well is with a vertical well (This is the shortest distance to the target because the measured depth, MD (the length that is actually drilled), is equal to the true vertical depth, TVD – see Figure 7.02.).

For offshore production wells, the most common wells tend to be deviated wells. In offshore drilling, we are normally dealing with a rig at one to three fixed drilling centers, the Production Platforms (there are other drilling centers). In these situations, the drilling rig is at a fixed position, and the vertical section of the well is drilled. The bottom-hole well target for the well is the desired location where we want to produce. In order to reach this location, we need to deviate from the vertical and drill towards the bottom-hole target. The point where we deviate from the vertical is referred to as the Kickoff Point. Deviated wells are typically more expensive than vertical wells because the measured depth is greater than the true vertical depth, so the drilled footage is greater. In addition, all casing and tubing will need to be the measured depth of the well, so costs such as casing, tubing, and cement, will be greater for a deviated well.

On-shore wells are now commonly drilled from Well Pads (temporary, compact drilling sites that are prepared specifically for drilling using local materials – for example, gravel and wood – and then removed once drilling operations are completed). Pad drilling is a relatively recent innovation and, as it turns out, deviated wells drilled from Multi-Well Pads can leave a smaller environmental footprint than vertical wells drilled from Single-Well Pads. Therefore, there is an environmental incentive for drilling deviated wells from multi-well pads. There may not be an economic incentive for multi-well pad drilling as any synergies and cost reductions captured at the surface must compensate any cost increases associated with the deviated well.

Figure 7.03 Complex Multi-Lateral Well Orientations used in the Oil and Gas Industry

Source: Based on Sadegh Elyasi: "Assessment and evaluation of degree of multilateral well’s performance for determination of their role in oil recovery at a fractured reservoir in Iran [2],” Egyptian Journal of Petroleum, January 2016

Deviated wells drilled from multi-well pads are similar to deviated wells drilled from an offshore drilling center. Wells with a common surface location are drilled to different bottom-hole targets identified by geologists and reservoir engineers.

There are many uses for deviated and horizontal (or single-lateral) wells. These include to:

avoid well surface locations that:
- are environmentally sensitive;
- are logistically difficult (heavily forested, no suitable access roads or infrastructure, heavily populated regions, etc.);
drill an offshore bottom-hole target from an onshore surface location;
produce from thin formations;
produce from low permeability formations
produce a thin oil column in a gas or gas condensate reservoir;
maximize the contact area of the well and reservoir;
reduce pressure drop near the well:
- minimize production of unwanted fluids in Coning situations (I will discuss coning later in this lesson);
- minimize sand production;
intercept natural fractures in naturally fractured reservoirs;
assist in steam drive production of heavy oils.

If the bottom-hole target location of a well is positioned directly below a non-desirable surface location from environmental, economic, logistics, or safety perspectives, then vertical wells may not be the best option if the target location can be reached with a deviated or horizontal well. If a more desirable surface location can be found within the Drilling Radius for that bottom-hole location, then deviated or horizontal wells should be considered.

From a production perspective, horizontal wells are often more desirable for thin bottom-hole targets (reservoirs or oil columns). While vertical well lengths are limited to the reservoir thickness, that restriction does not apply to horizontal wells (see Figure 7.02). The longer the well length, the more contact area is exposed to the well. This increases the inflow performance of the well and results in higher production rates at comparable or lower drawdowns. One advantage of these lower drawdown pressures is that this helps reduce production of unwanted fluids in coning situations. I will discuss this later in this lesson.

Finally, for specialized situations, such as Naturally Fractured Reservoirs or Steam Flooding, horizontal wells also have applications.

7.5: Well Completion Design

The well completion is the lowermost portion of the well, comprised of tubulars and downhole equipment, that enables the safe and effective production from an oil or gas well. The objectives of the completion are to:

connect the reservoir to the production tubing;
provide a conduit for well stimulation fluids;
protect the well from sand/fines production;
isolate productive zones from non-producing zones;
- isolate oil producing zones from high GOR (gas-oil ratio) and high watercut zones in oil reservoirs;
- isolate gas producing zones from high GLR (gas-liquid ratio) zone in gas reservoirs;
provide a means to measure changes in reservoir conditions (pressure, saturation, rate) by well tests, cased-hole logs, and production logs.

Before we can discuss well completions, we will need to discuss sources of production problems. The problems that we will further discuss in this lesson are production of sand and production of unwanted fluids (gas and water from oil reservoirs and water from gas reservoirs).

We have already discussed that in reservoirs made of unconsolidated reservoir rock or in reservoirs with fine rock materials, there is a possibility that the rock material and debris may be dragged along with the produced fluids and enter the well. As I mentioned earlier, this this is referred to as Fines Movement or Fines Migration. Once inside the well, if the velocity of the fluids going up the well is less than the settling velocity of the sand, then Sand Fill will occur in the well. Sand fill is the settling of sand and debris originating from the reservoir which entered the well and settled on the bottom of the well. This has the potential to cover some or all of the perforations in a perforated well. This is illustrated in Figure 7.04.

In this figure, sand fill has covered approximately half of the perforations and is severely restricting flow from the reservoir. The ineffective perforations and the restricted flow shown in Figure 7.04 result in well damage and is quantified as a Skin Factor in our Inflow Performance calculations.

If the velocities of the fluids are greater than the settling velocity of the sand, then produced sand will continue upward and cause erosion of the tubing and possible damage to any down-hole equipment (down-hole pumps, pressure gauges, etc.). The detection and avoidance of sand production is referred to as Sand Control.

Another potential problem in hydrocarbon production is the production of unwanted reservoirs fluids. As petroleum engineers, we are attempting maximize the recovery and profit of a well for our employers and key stake holders. To achieve this, we are interested in producing the most valuable resource from the well. In the case of oil reservoirs, this means the production of oil. While natural gas is also produced from oil reservoirs and has a sales value, crude oil has historically commanded a higher commodities price than natural gas. Consequently, production engineers working on oil reservoirs will focus their attention on oil production and, in fact, in many cases attempt to shut off gas production.

Figure 7.04: Fines Migration and Sand Fill

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

As we have seen in earlier lessons, free gas in the reservoir (either liberated solution gas or initial free gas) expands and displaces oil to the production wells. This expanding gas is the cause of two of the oil drive mechanisms: solution gas drive (liberated solution gas) and gas cap drive (initial free gas). From the reservoir side, the production of the free gas results in removing a source of reservoir energy available to oil production.

From the tubing side, the production of free gas can have different impacts based on the production rate of the free gas, $q_{g}$ At low rates, the addition of gas will lighten the well column and aid oil production. On the other hand, excessive gas rates may result in higher frictional losses and, in turn, result in a high back-pressure across the perforations. From our discussions on inflow performance and Darcy’s Law, we saw that the lower that we can keep the flowing well pressure, $p_{w f}$ the greater the drawdown will be and the higher the oil production rate will be. It is the role of the production engineer to assess the impact of gas production (both from the reservoir side and the tubing side) to determine if/when gas shut-off is required.

For both oil reservoirs and gas reservoirs, the production of water is always avoided if economically warranted. Since water is a heaver fluid than either gas or oil, water production results in a heavier well column and a larger back-pressure across the perforations. In addition, depending on the produced water chemistry, it may need to be treated to remove any heavy metals and disposed of. Water treatment and disposal require additional costs which reduce the economics of the well.

The detection, avoidance, treatment, and disposal of water is referred to as Water Control. The best method of water control is to shut off water in the reservoir. There are three common causes of production of unwanted fluid production. These are:

lateral fluid movement from a gas cap or aquifer,
lateral fluid movement from gas or water injection, and
gas and water production from coning.

These mechanisms are shown in Figure 7.05 in the context of water production. In Figure 7.05 (A), water is being pulled laterally from the aquifer by the production from the well. The movement of water from the aquifer to the well is, in large part, governed by the permeability of the different reservoir layers with the water moving faster in the reservoir units with the highest permeability. In Figure 7.05 (B), water is being injected into the reservoir. The objective of this secondary waterflood is to displace oil to the production well with the injected water. At some point, the injected water Breaks Through to the production well resulting in increased producing watercuts. Finally, in Figure 7.05 (C), water is being pulled upward from a underlying or Bottom Water Aquifer. The production of water in this manner is referred to as water coning.

Figure 7.05: Common Water Production Problems.

(A) Production Well with Lateral, Edge-Water Production.
(B) Production Well with Lateral, Injected-Water Production.
(C) Production Well with Bottom-Water Coning Production.

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

Each of these water producing mechanisms has a direct analog with a gas production mechanism. These gas production mechanisms are shown in Figure 7.06. The avoidance of production of sand and unwanted fluids are two major design criteria for well completions.

There are many types of completions, however, we will focus on the following:

an Open-Hole or Bare Foot completion
a Screen or Liner completion
- Slotted Liner completion
- Screen completion
- Gravel pack completion
Cased and Perforated completion

7.5.1: Open Hole and Barefoot Completion

The least complex and least costly well completion is a Barefoot, Open-Hole completion. An open-hole completion is a completion that does not have any casing or tubulars cemented across the reservoir section, while a barefoot completion has no tubulars, casing or tubing, across the reservoir section (a barefoot completion is a subset of an open-hole completion). Two examples of barefoot, open-hole completions are shown in Figure 7.07, one without tubing and one with tubing.

Figure 7.06 Common Gas Production Problems.

(A) Production Well with Lateral Gas Production from the Gas Cap.
(B) Production Well with Lateral Gas Production from the Injection Well.
(C) Production Well with Gas Coning from the Gas Cap.

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

As with all decisions on completion design, there are advantages, disadvantages, and trade-offs associated with each decision regarding the open-hole, barefoot completions.

The advantages of a barefoot, open-hole completion include:

they are the least expensive completion technique;
they are adaptable to special drilling techniques that minimize reservoir damage (wells can be drilled to the top of the reservoir, casing set and cemented in place, and drilling/completion fluids changed to less damaging fluids for drilling through the reservoir);
no perforating expenses;
no issues with open-hole logging (time-lapse open-hole logs can be run for improved reservoir characterization and surveillance);
large wellbore radius, $r_{w}$ , across the reservoir (From Lesson 4 and Lesson 5, we saw that a large wellbore radius improves Productivity Index and Inflow Performance – Table 7.01 and Table 7.02 have been reproduced to illustrate this point and to aid in later discussions);
large diameter conduit to surface which results in lower pressure losses in high production rate wells (in Lesson 6, we saw that the pressure losses were significantly impacted by the $D_{I D}$ the inner diameter of the conduit to the flow);
the well can be easily deepened if desired;
the completion can be modified at a later date with an inner casing string or liner if desired.

The disadvantages of a barefoot, open-hole completion include:

as illustrated, sand production cannot be permanently controlled without a Major Rig Workover, MRWO (an expensive well intervention requiring a drilling rig and hoist). Temporary sand control can be performed with multiple bailer/clean-out well interventions (less expensive Slickline Workover). We will discuss Major Rig Workovers, Coiled Tubing Workovers, Wireline Workovers, and Slickline Workovers later in this lesson;
as illustrated, excessive gas or water production cannot be easily controlled;
selective well stimulation (acidizing or hydraulic fracturing of specific depth(s) in the reservoir) more difficult than with Cased and Perforated Completions;
while the large diameter conduit for fluids flowing to the surface has the advantage of lower pressure losses, it has the disadvantage of lower velocity for the same volumetric rate. If the velocity of multiphase flow is too low, then the heavier fluids may segregate toward the bottom of the well causing a segregated water phase across the reservoir.

Figure 7.07a: Example of a Barefoot, Open-Hole Well Completion without Tubing

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

Figure 7.07b: Example of a Barefoot, Open-Hole Well Completion with Tubing

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

From the lists of advantages and disadvantages for barefoot, open-hole completions, we can see that these well completions would typically target reservoirs locations with limited chance of production of sand or unwanted fluids. These completion designs also illustrate that a field-wide well completion to be used on each and every well may not be desirable. For example, production wells close to a source of gas or water (see Figure 7.05 and Figure 7.06) may not be good candidates for the barefoot open-hole completions shown in Figure 7.07, while wells in the same reservoir down-dip from the gas cap or up-dip from the aquifer may be suitable candidates for these completions. In terms of sand control, the well completions shown in Figure 7.07 normally target hard, consolidated reservoir rocks.

There are several features of the well completions shown in Figure 7.07 that require further discussion. One common feature to these well completions is that there are no tubulars (casing or tubing) across the sandface. By definition, this is what makes these two completions barefoot completions. A second common feature to these completions is that casing has been set at the top of the reservoir. There are several reasons for running and setting this casing. These include:

preventing reservoir fluids from entering porous and permeable formations above the reservoir;
preventing heavier fluids from porous and permeable formations above the reservoir from entering the reservoir;
preventing rock material and drilling debris from formations above the reservoir from entering the wellbore and settling across the reservoir sandface;
preventing catastrophic wellbore collapse and loss of the well.

As seen in Figure 7.07, we can run a barefoot completion with or without a tubing string. Again, there are advantages and disadvantages to running a tubing string.

The advantages of running a tubing string include:

the tubing permits for easy Circulation of fluids (corrosion inhibitors, scale inhibitors, solvents, Workover Fluids, or Kill Fluids) down the tubing and up the annulus (or Reverse Circulating fluids down the annulus and up the tubing). By running a tubing string without a production packer, we are setting up a three-dimensional U-Tube for these circulation process. Note, there are ways to circulate fluids with the temporary installation of Coiled Tubing (spooled tubing capable of being run into the well with the use of a drilling rig).
provides multiple flow paths for artificial lift systems.
protects the casing from erosion, corrosion, abrasion, or excess pressures.
provides a means for monitoring bottom-hole pressures.

The disadvantages of running the tubing string in the completion in Figure 7.07 (B) are:

the cost of the tubing;
the rig time required to run the tubing:
- costs involved in paying the Day Rate for the rig;
- deferred production and revenue from the well.

Even the decision to run or not to run a Production Packer has advantages, disadvantages, trade-offs, and costs associated with it. A packer is device that is used to provide annular isolation for the well (prevent fluid flow through the annular space between the tubing and casing) and to anchor (secure) the tubing string to the production casing.

The advantages of including the production packer in the completion are:

most common means of providing zonal control (isolation of reservoir layers) used in the industry
isolates casing leaks or poor cement jobs in the well:
- protects the well from unwanted fluids entering the well;
- protects the subsurface environment from produced fluids exiting the well;
protects the casing from excess pressure and corrosive fluids;
protects the tubing from tubing leaks (Without a packer, the annular space between the tubing and casing will be filled with a static gas column while the tubing will be with a flowing liquid. The pressure differential caused by this pressure gradient disparity is conducive to tubing leaks. With a packer, the annular space is filled with a static fluid while the tubing is filled with a flowing fluid. This reduced pressure differential helps to prevent tubing leaks.)
well safety (in conjunction with sub-surface safety valves)
supports some of the weight of the tubing string
some artificial lift systems

Many of these objectives, advantages, and disadvantages will become more clear later in the lesson when we discuss Zonal Isolation.

The disadvantage of running a Production packer are:

additional cost (packer costs);
difficulty in Recompleting the Well:
- Retrievable Packers can be easily unseated and removed; however, are much more expensive for the same functionality and less reliable than a permanent packer;
- Permanent Packers are extremely difficult to remove from a well once seated. To remove a permanent packer, the tubing above the packer must be removed (a standard operating procedure in the field), but the permanent packer must be milled out with a drilling rig and special milling bit.

Figure 7.08 is a schematic diagram of a simple, retrievable packer. I am supplying this Petrowiki link in the text (as well as in the reference) because the article contains a lot of good information on well completions and packers. While I was at it, I also provided the link to a Wikipedia article on well completions. The Wikipedia article has a good glossary of terms for much of the equipment that I will be discussing in the remainder of this lesson (and some terms that I will not be discussing). The links to these two articles are:

PetroWiki Article ^[1]: Packers [3]
Wikipedia Article: Completion (Oil and Gas Wells) [4]

Figure 7.08a: Schematic Diagram of a Retrievable, Tension Packer

Source: PetroWiki Article: Packers [3]

Figure 7.08b: 3D model of a Retrievable, Tension Packer
Use your mouse wheel to zoom in and out, left mouse button to rotate, and right mouse button to move the model.

Viewer: viewstl.com [5]

Source: Mark Wherley © Penn State, licensed CC BY-NC-SA 4.0 [1]

In this schematic, the threads at the top and the bottom of the packer are used to couple it to the tubing string. The packing element in the schematic is the element that creates the seal in the annulus. There are many ways that a packer can be actuated. These include:

mechanical actuation (applying weight from the tubing string and rotating it with the rig). This is the actuation method used in the schematic diagram. Weight from the tubing string causes the sealing element to compress outward forming the seal;
pressure actuation (inflating the sealing element with pressurized drilling, completion, or work over fluid);
electrically actuated (inflating the sealing element with an electrically controlled pump – both pump and packer are run at the end of wire line. This method of actuation is typically used for tubing retrievable packer.)

The two links that I supplied provide additional information on the design aspects of production packers. As I mentioned earlier, the completions shown in Figure 7.07, the decision to use a production packer or not may be optional. When we begin to discuss Zonal Isolation, the use of the packers will become required.

As you can see from this discussion, the production engineer must make many decisions for a well completion, even for a completion as basic as that shown in Figure 7.07. The criteria for these decisions were listed in the first bullet list in the Well Design Section: The Overriding Well Design Considerations bullet list. One key aspect of the production engineers’ job is to be kept informed on the latest innovations is sub-surface well technology.

[1] Society of Petroleum Engineers technology website: Petrowiki [6]

7.5.2: Liner Completion

As we discussed earlier, barefoot completions normally target hard, consolidated reservoir rocks. Wells in reservoirs that are susceptible to sand production will require different well completions. For wells requiring sand control, we can use Open-Hole Slotted Liner Completions, Open-Hole Screen Completions, or most commonly, Gravel Pack Completions.

A liner is a casing string that does not go to the surface. A typical Cemented Liner Completion is shown in Figure 7.09 (A). This particular completion does not offer any sand control capability but is included here to introduce the concept of a liner. As we can see from this figure, the liner does not go to the surface but is hung from a Liner Hanger. The cemented liner completion has many of the advantages of a Cased and Perforated Completion (to be discussed) but at a reduced cost. Because the liner in this completion is cemented in-place, (A) it does not represent an open-hole completion and (2) it requires perforations for the well to access the reservoir.

The other completion in Figure 7.09 (B) either the Slotted Liner Completion or the Screen Completion, is an open-hole completion and does offer some sand control capability. Note that we have not cemented the slotted liner or screen set across the reservoir, so these are open-hole completions, but not barefoot completions.

A slotted liner is a liner with pre-milled slots, while a screen is a liner with pre-milled holes. These liners do not require perforations to achieve access to the reservoir. Figure 7.10 provides a more detailed illustration of these liner types.

There are many applications for slotted liners and screens but in the context of this discussion, they provide partial sand control with the physical dimensions of the openings acting as filters against the sand production. This sand control, however, is limited because the openings may eventually plug, causing a reduction in the oil rate.

The most common method of sand control is with gravel pack completions. Two examples of gravel pack completions, one cased and perforated completion and one open-hole completion, are shown in Figure 7.11. In these completions, gravel is placed either between a slotted liner (or screen) and the casing (or sandface) to act as a filter for the formation sand.

The gravel is selected to have good permeability so as not to create a significant pressure drop through the gravel pack and to have good filtering capability. This gravel is often treated with resin to improve its filtering capability.

There are many variants to the gravel pack, such as pre-packed liners or screens (two concentric slotted liners or screens with gravel pre-packed between them) or frac-pack (combination of hydraulic fracturing and gravel packing ^[2]. This further illustrates the need for the production engineer to work with the oilfield service providers and manufacturers to be aware of all technology innovations. In fact, a significant portion of the production engineer’s time is working with the service companies and manufactures to develop solutions for the completion needs of their wells.

I have included the link to an article from the Schlumberger Oilfield Review with a lot of good information on sand control and frac-packing:

Schlumberger Oilfield Review ^[2]: Frac Packing - Fracturing for Sand Control [7]

Figure 7.09a: Example of a Cemented Liner Completion without Tubing

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

Figure 7.09b: Example of either Open-Hole Slotted Liner or Screen Completion without Tubing

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

Figure 7.10: Slotted Liner and Screen

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

Figure 7.11a: Example of a Cased and Perforated Gravel Pack Completion without Tubing

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

Figure 7.11b: Example of an Open-Hole Gravel Pack Open-Hole Completion^(A)

(A) Note that the casing in Figure 7.11a goes to the bottom of the reservoir, while the casing in Figure 7.11b stops at the top of the reservoir.

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

[2] Schlumberger Oilfield Review: Frac Packing: Fracturing for Sand Control [7]

7.5.3: Cased and Perforated Completion

An example of a Cased and Perforated (“Cased and Perf’ed”) Completion across a single-layer reservoir is shown in Figure 7.12.

The advantages of a cased and perforated completion in the well (Figure 7.12) include:

in single-layer reservoirs, a cased and perforated completion is a simple, durable completion;
for multiple-layer reservoirs, a cased and perforated completion allows for zonal isolation for different zones;
for multiple-layer reservoirs, a cased and perforated completion allows selective stimulation (different stimulation treatments for different reservoir zones);
very flexible with many possible cased and perforated completions available for the same problems.

The disadvantages of a cased and perforated completion in the well (Figure 7.12) include:

the costs of the perforating thick reservoir zones may be excessive;
well logs for future reservoir evaluation, workover planning, or determination to Plug and Abandon the well are limited to Cased Hole Logs (subset of well logs that are not impacted or are designed not to be impacted by the presence of the casing);
deepening of the well is more difficult than in open-hole completions.

As alluded to throughout the lesson, casing is high quality steel pipe that is major structural part of the oil or gas wells. Off the shelf, the casing has no openings and, consequently, requires Perforation to gain access to the reservoir. There are many grades and specifications for the casing steel quality. The objectives of the casing are:

provide wellbore stability;
protect natural aquifers from work fluids and produced fluids;
control well pressures during drilling, production, and workovers;
aid in zonal isolation in cased and perforated well completions.

Figure 7.12: Example Cased and Perforated Completion in a Single Zone Reservoir

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

All modern wells use strings of multiple casing. The casing strings that can be used in the oil and gas wells include:

conductor casing
surface casing
intermediate casing
production casing
liner
liner tie-back casing

Several of these casing strings are shown in Figure 7.13. We will discuss the different casing strings and their roles in drilling the well in Lesson 8 when we discuss drilling operations. In our current discussion on cased and perforated completions, however, we are referring to the production casing. The role of the production casing is to:

aid in zonal isolation;
protect the wellbore and the outer casing strings from reservoir pressures;
protect the well and environment in case of a tubing leak.

Schematic showing how a well typical vertical well casings taper from a wide surface casing at the top to a narrow production casing at the bottom.

Figure 7.13: Casing Run in Modern Oil and Gas Wells

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

Cased and perforated wells are completed by first drilling through the reservoir (or sometimes a little deeper than the bottom of the reservoir). The production casing is then run and cemented in-place. Next, the tubing string is run, and all packers are set. Finally, the perforation guns are run and fired to create the access to the reservoir.

A perforation gun is an array of shaped charges that can be arranged in many configurations to achieve the objectives of the well. The perforation guns can be conveyed (deployed) either on wireline (wireline conveyed perforation guns) or on the tubing itself (Tubing Conveyed Perforation, TCP, guns). Figure 7.14 shows a typical TCP gun.

Cased and perforated completions provide the highest level of control for the well, and when used in conjunction of systems of Packers and Bridge Plugs, are capable of providing Zonal Isolation across multiple reservoir zones.

We have already discussed packers earlier in the lesson (see Figure 7.08). As I stated, packers provide isolation in the annulus of the well. On the other hand, bridge plugs provide isolation inside the tubing of the well. Figure 7.15 shows a picture of a bridge plug. The bridge plug can either be conveyed on a wireline or with a workover string. The sealing element of the bridge plug is then set inside the tubing to create the isolation. A bridge plug can be either retrievable or permanent.

Figure 7.14: Typical Tubing Conveyed Perforation, TCP, Guns

Source: The Expro Group: Tubing Conveyed for Well Testing [8]

We are now in a position to discuss the role of well completions and Zonal Isolation. I think many of the concepts on zonal isolation that we discussed earlier in the lesson will become much clearer starting from this point.

In our earlier examples, Figure 7.07 through Figure 7.12, we considered a reservoir with a single layer or zone. Now, let’s consider a reservoir with two reservoir zones with the possibility of producing unwanted fluids from one or both of the zones as shown in Figure 7.05 and Figure 7.06.

If we know that water will be produced from the lower reservoir interval (a common problem based on the density of water compared to that of gas or oil), then we may consider a well completion such as that shown in Figure 7.16. This completion is a common completion when we are certain that water will enter the well in the lowermost zone.

In Figure 7-16 (A), the well is initially completed with no bridge plug installed. The Blast Joint shown in this figure is a thicker walled / stronger section of tubing that is placed across all perforations in multiple zone completions to protect the production tubing string from erosion due to the jetting action of produced fluids through the perforations. In the configuration shown in Figure 7.16 (A), oil production is allowed from both reservoir zones with the fluids from the lower zone, Reservoir Zone 1, being produced through the tubing and fluids from higher zone, Reservoir Zone 2, being produced through the Annulus (space between the tubing and casing).

At some later date, water production occurs from the lower reservoir zone, Reservoir Zone 1, from one of the water sources shown in Figure 7.5. When this water production becomes too excessive, a bridge plug can be run through the tubing on wireline and seated at the appropriate depth as in Figure 7.16 (B). This is what we refer to as zonal isolation which we use to isolate production of unwanted fluids.

The action of running and seating the bridge plug at a date after production has begun is referred to as a Well Intervention or a Workover. In the case of this example, this is specifically referred to as a Water Shut-Off Workover. Since we are able to the run the bridge plug on a wireline through the tubing (not requiring a drilling rig), we can also refer to this as a Wireline Workover or a Through-Tubing Workover.

Figure 7.15: Typical Bridge Plug used for Preventing Fluid Movement Inside Tubing

Source: American Completion Tools: Model BKR Premium Bridge Plug - Wireline Set / Drillable [9]

For the well’s initial completion Figure 7.16 (A), water production from the lower intervals (as opposed to water production from higher layers – see Figure 7.05) may be assessed prior to drilling the well by the behavior of Offset (neighboring) wells or with open-hole logs and Drill Stem Tests (DSTs) after drilling the well. If the well is in an exploratory geologic basin or new field or reservoir, then you need to incorporate flexibility into completion designs of the early wells.

The advantages of this completion (Figure 7.16) are:

produce oil at high rates due to flow through both the tubing and annulus resulting in faster payout for the well and the possibility of improved long-term economics;
provide the ability to selectively isolate (shut-off) the bottom zone, Reservoir Zone 1, with a relatively inexpensive wireline workover.

The disadvantages of this completion (Figure 7.16) are:

the upper zone cannot be produced through the tubing;
only the zone serviced by the tubing can be isolated with a relatively inexpensive bridge plug;
working over the upper zone requires the temporary shut-in of both zones;
the casing is subjected to higher pressures (the pressure of Reservoir Layer 2), corrosion, and erosion from production;
the potential for tubing leaks to develop if a differential pressure exists due to differential reservoir pressures;
only the lower zone (the zone being produced through the tubing) can be assisted with artificial lift;
sand production from the upper zone may create sand-fill in the annulus and cause stuck pipe if the tubing is attempted to be pulled (a Tubing Change-Out Workover).

Figure 7.16a: An Example of a Cased and Perforated Completion with Tubing and Blast Joint Prior to a Water Shut-Off Workover

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

Figure 7.16b: An Example of a Cased and Perforated Completion with Tubing, Blast Joint, and Bridge Plug after a Through-Tubing Water Shut-Off Workover

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

To help illustrate the flexibility of the cased and perforated completion, if water is known to be produced from the upper layer, Reservoir Zone 2, then there are tools available (cross-over valve/choke) which can be used to change the flow paths for the produced fluids. That is, at the time of implementing the original completion, if it is suspected that water production may come from the upper zone, then a cross-over valve can be installed to have the fluids from the lower interval, Reservoir Zone 1, enter the well as in this figure but cross-over to the annulus up-hole, while the fluids from the higher interval enter the well as seen in the figure but cross-over to the tubing. In this case, we would be able to isolate the upper zone (now produced through the tubing) with a bridge plug, but not the lower zone (now produced through the annulus).

Again, to further illustrate the flexibility of the cased hole and perforated completion, we can discuss another well completion for this well. From the list of disadvantages for this completion, we see that we are subjecting the casing to high levels of well stress (high pressures, possible corrosion, and possible erosion). If a critical objective of the well is to protect the casing from these well stresses, then the well completion shown in Figure 7.17 may be considered.

Figure 7.17a: Second Example of a Cased and Perforated Completion with Packer — Tail-Pipe Assembly

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

Figure 7.17b: Second Example of a Cased and Perforated Completion with Packer — Tail-Pipe Assembly and Bridge Plug

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

This example shows the same two-zone reservoir as in the earlier example (Figure 7.16). In this completion, we have used a Packer – Tail-Pipe Assembly to provide zonal isolation of the water prone, lower layer. This completion, however, results in commingled (mixed) production from the two layers in the tubing. Commingled production may result in production problems if the fluid chemistries in the produced fluids are incompatible. Wax or asphaltene deposition may occur from the two oils if they are significantly different, while scale deposition from produced waters may occur it the chemistries (dissolved solids) of the produced waters are significantly different.

The advantages of this completion (Figure 7.17) are:

there is no annular flow, so there are no issues with high pressures, corrosion, or erosion acting on the casing;
the pressure gradient in the annulus and tubing are approximately equal which protects the tubing from tubing leaks.

The disadvantages of this completion (Figure 7.17) are:

lower production rates – both reservoir zones are being produced through a single tubing string. The smaller cross-sectional area for flow creates a larger pressure drop in the tubing and restricts the total production from the well;
production from the two reservoir zones is commingled;
only the lower zone can be isolated with a relatively inexpensive bridge plug.

We can design a third completion for this well and two-zone reservoir which addresses some of the disadvantages of the packer – tail pipe assembly. This type of completion is referred to as a dual-string completion and is shown in Figure 7.18.

Figure 7.18: Third Example of a Cased and Perforated Well Completion: Use of a Dual-String Completion

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

In Figure 7.18, we have completed the well with two tubing strings. The key to this completion is the dual-packer. This type of completion can only be run if the original wellbore and production casing have sufficient Inner Diameters to support this equipment and the tools required to run this equipment. This issue is typically considered during the design and planning stage of the well, and if a dual-string completion is to be used in the well, then a larger diameter well can be drilled.

A detailed schematic of a dual packer is shown in Figure 7.19.

The advantages of this completion (Figure 7.19) are:

there is no annular flow, so there are no issues with high pressures, corrosion, or erosion acting on the casing;
the pressure gradient in the annulus and tubing are approximately equal which protects the tubing from tubing leaks;
wireline workovers practical for both reservoir zones;
production from the two reservoir zones is not commingled;
both zones can be isolated with a relatively inexpensive bridge plug.

Figure 7.19: Dual Packer

Source: PetroWiki Article: Packers [3]

The disadvantages of this completion (Figure 7.19) are:

expensive completion (two tubing strings);
the dual string completion is a complex well completion;
these completions can only be run if the wellbore and production casing have sufficiently large inner diameters;
lower production rates – production rates are lower because the cross-section to flow is further reduced;
logging the well may be problematic as logging tools must be available for the restricted dimensions in these completions.

To this point, we have limited our discussion to two-zone reservoirs. I will provide one last example of multi-zone well completion using Sliding Sleeves. This multi-zone completion can also be used for the two-zone reservoir example that we have been discussing. A sliding sleeve completion for a multiple zone reservoir is shown in Figure 7.20.

A sliding sleeve is a device that is run as part of the tubing string that can be shifted to an open position to allow communication between the tubing and annulus or shifted into a closed position to prevent tubing-annuls communication. The sliding sleeve can be shifted to the open or closed position multiple times using wireline or coiled tubing. In this completion, the lowest reservoir zone can be isolated with a bridge plug.

Figure 7.20: Example of a Cased and Perforated Well Completion in a Multi-Zone Reservoir: Use of a Sliding Sleeve

Source: Greg King © Penn State, licensed CC BY-NC-SA 4.0 [1]

The advantages of this completion (Figure 7.20) are:

there is no annular flow, so there are no issues with high pressures, corrosion, or erosion acting on the casing;
the pressure gradient in the annulus and tubing are approximately equal which protects the tubing from tubing leaks (the sliding sleeves themselves may leak);
all zones can be isolated with a relatively inexpensive wireline or coiled tubing workover.

The disadvantages of this completion (Figure 7.20) are:

high costs for multiple sliding sleeves and packers;
lower production rates – production from all reservoirs zones flow through a common tubing string;
the sliding sleeve completion is a very complex well completion (sliding sleeves and packers susceptible to failure);
difficulty in monitoring performance of individual reservoir zones.

In the bullet list of overriding Well Design Considerations, we listed simplicity as one of the overarching goals for the well completion. As we have seen in these examples, there may be number of completions that can be used to achieve the specific objectives of the well: sand control, unwanted fluid control, etc. As we have also seen, these well completions can get very complex. One measure of the complexity of the completion is by the number of packers that are required by the completion. Remember, any piece of equipment put into a well; a packer, a bridge plug, a sliding sleeve; can fail. By keeping the completion design simple we are reducing the possibility of the entire completion failing based on the failure of one key component.

We are always trying to make our completions as simple as possible with the ability to achieve the completion objectives: sand control, water control, gas control, amongst others. When we design the completion, we can try to reduce the complexity of the completion by grouping layers in the reservoir. If several adjacent reservoir layers act in unison, then we can reduce the complexity of the completion by grouping the layers as if they were a single layer.

7.6: Tubing Size

We have just considered two design aspects of a well: the orientation of the well and the well completion design. A third aspect of the well design is the tubing size. In Lesson 4 and Lesson 5, we discussed the stabilized production rates from oil wells and gas wells, respectively. Ideally, we would like to design the size of the well tubing to be capable of producing all of the oil or gas without creating a bottleneck in the production. In those lessons, we saw that the inflow performance relationship, IPR, could be represented by the general equation (formerly Equation 4.41):

q = P I (p - p_{w f}) = P I Δ p

Equation 7.01

Where:

q is either the oil production rate (Table 7.01) or gas production rate (Table 7.02):
- Oil: STB/day
- Gas: SCF/day
PI is the Productivity Index of the well (see Tables for details):
- Oil: STB/(day-psi)
- Gas:
  - Pressure Approach: SCF/(day-psi)
  - Pressure-Squared Approach: SCF/(day-psi²)
  - Pseudo-Pressure Approach: SCF/(day-psi²/cp)
  - Rawlins and Schellhardt Backpressure Approach^[3]: SCF/(day-psi²ⁿ)
Drawdown, Δp or its equivalent (see Tables for details):
- Oil: psi
- Gas:
  - Pressure Approach: psi
  - Pressure-Squared Approach: psi²
  - Pseudo-Pressure Approach: psi²/cp
  - Rawlins and Schellhardt Backpressure Approach^[3]: psi²ⁿ

In Lesson 4 and Lesson 5, we assumed that we knew the flowing pressure, $p_{w f}$ , or its equivalent, $p_{w f}^{2}$ , $m (p_{w f})$ etc. in Equation 7.01. With that assumption, we were able to calculate the flow rate from the reservoir to the well. What we did not consider at that time was the impact of the tubing and completion.

Table 7.01: Stabilized Inflow Performance Relationships for Oil Wells (previously Table 4.02)^[A]
	Steady-State Flow Regime	Pseudo Steady-State Flow Regime
Pressure Distribution	$p = p_{w f} + \frac{141.22 μ B q_{o}}{k h} l o g_{e} (\frac{r}{r_{w}})$	$p = p_{w f} + \frac{141.22 μ B q_{o}}{k h} [l o g_{e} (\frac{r}{r_{w}}) - (\frac{r^{2}}{r_{e}^{2}})]$
	In terms of $p_{e}$ at the external radius, $r_{e}$ , of the drainage volume
Drawdown	$p_{e} - p_{w f}$	$p_{e} - p_{w f}$
Productivity Index	$\frac{k h}{141.22 μ B [l o g_{e} (\frac{r_{e}}{r_{w}}) + S]}$	$\frac{k h}{141.22 μ B [l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S]}$
IPR	$q_{o} = \frac{k h (p_{e} - p_{w f})}{141.22 μ B [l o g_{e} (\frac{r_{e}}{r_{w}}) + S]}$	$q_{o} = \frac{k h (p_{e} - p_{w f})}{141.22 μ B [l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S]}$
	In terms of $\bar{p}$ in the interior of the drainage volume
Drawdown	$\bar{p} - p_{w f}$	$\bar{p} - p_{w f}$
Productivity Index	$\frac{k h}{141.22 μ B [l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S]}$	$\frac{k h}{141.22 μ B [l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{3}{4} + S]}$
IPR	$q_{o} = \frac{k h (\bar{p} - p_{w f})}{141.22 μ B [l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S]}$	$q_{o} = \frac{k h (\bar{p} - p_{w f})}{141.22 μ B [l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{3}{4} + S]}$
[A] Note, we did derive the equations in the shaded cells, but they are included for future reference.

Table 7.02a: Stabilized Inflow Performance Relationships for Gas Wells (previously Table 5.01a)
In Terms of Pressure $(p_{e})$ including Damage or Stimulation: All pressures greater than 3,000 psi
	Steady-State Flow Regime	Pseudo Steady-State Flow Regime
Drawdown	$p_{e} - p_{w f}$	$p_{e} - p_{w f}$
Productivity Index	$\frac{0.03976 T_{S C}}{T_{r} p_{S C}} (\bar{\frac{p}{μ_{g} Z}}) \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) + S}$	$\frac{0.03976 T_{S C}}{T_{r} p_{S C}} (\bar{\frac{p}{μ_{g} Z}}) \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$
IPR	$q_{g} = \frac{0.03976 T_{S C}}{T_{r} p_{S C}} (\bar{\frac{p}{μ_{g} Z}}) \frac{k_{g} h (p_{e} - p_{w f})}{l o g_{e} (\frac{r_{e}}{r_{w}}) + S}$	$q_{g} = \frac{0.03976 T_{S C}}{T_{r} p_{S C}} (\bar{\frac{p}{μ_{g} Z}}) \frac{k_{g} h (p_{e} - p_{w f})}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$

Table 7.02b: Stabilized Inflow Performance Relationships for Gas Wells
(previously Table 5.01b)
In terms of Pressure $(\bar{p})$ including Damage or Stimulation: All pressures greater than 3,000 psi
	Steady-State Flow Regime	Pseudo Steady-State Flow Regime
Drawdown	$\bar{p} - p_{w f}$	$\bar{p} - p_{w f}$
Productivity Index	$\frac{0.03976 T_{S C}}{T_{r} p_{S C}} (\bar{\frac{p}{μ_{g} Z}}) \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$	$\frac{0.03976 T_{S C}}{T_{r} p_{S C}} (\bar{\frac{p}{μ_{g} Z}}) \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{3}{4} + S}$
IPR	$q_{g} = \frac{0.03976 T_{S C}}{T_{r} p_{S C}} (\bar{\frac{p}{μ_{g} Z}}) \frac{k_{g} h (\bar{p} - p_{w f})}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$	$q_{g} = \frac{0.03976 T_{S C}}{T_{r} p_{S C}} (\bar{\frac{p}{μ_{g} Z}}) \frac{k_{g} h (\bar{p} - p_{w f})}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{3}{4} + S}$

Table 7.02c: Stabilized Inflow Performance Relationships for Gas Wells (previously Table 5.01c)
In terms of Pressure-Squared $(p_{e})$ including Damage or Stimulation: All pressures less than 2,000 psi
	Steady-State Flow Regime	Pseudo Steady-State Flow Regime
Drawdown	$p_{e}^{2} - p_{w f}^{2}$	$p_{e}^{2} - p_{w f}^{2}$
Productivity Index	$\frac{0.01988 T_{S C}}{T_{r} p_{S C} μ_{g} Z} \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) + S}$	$\frac{0.01988 T_{S C}}{T_{r} p_{S C} μ_{g} Z} \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$
IPR	$q_{g} = \frac{0.01988 T_{S C}}{T_{r} p_{S C} μ_{g} Z} \frac{k_{g} h (p_{e}^{2} - p_{w f}^{2})}{l o g_{e} (\frac{r_{e}}{r_{w}}) + S}$	$q_{g} = \frac{0.01988 T_{S C}}{T_{r} p_{S C} μ_{g} Z} \frac{k_{g} h (p_{e}^{2} - p_{w f}^{2})}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$

Table 7.02d: Stabilized Inflow Performance Relationships for Gas Wells (previously Table 5.01d)
In terms of Pressure-Squared $(\bar{p})$ including Damage or Stimulation: All pressures less than 2,000 psi
	Steady-State Flow Regime	Pseudo Steady-State Flow Regime
Drawdown	${\bar{p}}^{2} - p_{w f}^{2}$	${\bar{p}}^{2} - p_{w f}^{2}$
Productivity Index	$\frac{0.01988 T_{S C}}{T_{r} p_{S C} μ_{g} Z} \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$	$\frac{0.01988 T_{S C}}{T_{r} p_{S C} μ_{g} Z} \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{3}{4} + S}$
IPR	$q_{g} = \frac{0.01988 T_{S C}}{T_{r} p_{S C} μ_{g} Z} \frac{k_{g} h ({\bar{p}}^{2} - p_{w f}^{2})}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$	$q_{g} = \frac{0.01988 T_{S C}}{T_{r} p_{S C} μ_{g} Z} \frac{k_{g} h ({\bar{p}}^{2} - p_{w f}^{2})}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{3}{4} + S}$

Table 7.02e: Stabilized Inflow Performance Relationships for Gas Wells (previously Table 5.01e)
In terms of the Real Gas Pseudo-Pressure $[m (p_{e})]$ including Damage or Stimulation: Valid over the entire pressure range
	Steady-State Flow Regime	Pseudo Steady-State Flow Regime
Drawdown	$m (p_{e}) - m (p_{w f})$	$m (p_{e}) - m (p_{w f})$
Productivity Index	$\frac{0.01988 T_{S C}}{T_{r} p_{S C}} \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) + S}$	$\frac{0.01988 T_{S C}}{T_{r} p_{S C}} \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$
IPR	$q_{g} = \frac{0.01988 T_{S C}}{T_{r} p_{S C}} \frac{k_{g} h [m (p_{e}) - m (p_{w f})]}{l o g_{e} (\frac{r_{e}}{r_{w}}) + S}$	$q_{g} = \frac{0.01988 T_{S C}}{T_{r} p_{S C}} \frac{k_{g} h [m (p_{e}) - m (p_{w f})]}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$

Table 7.02f: Stabilized Inflow Performance Relationships for Gas Wells (previously Table 5.01f)
In terms of the Real Gas Pseudo-Pressure $[m (\bar{p})]$ including Damage or Stimulation: Valid over the entire pressure range
	Steady-State Flow Regime	Pseudo Steady-State Flow Regime
Drawdown	$m (\bar{p}) - m (p_{w f})$	$m (\bar{p}) - m (p_{w f})$
Productivity Index	$\frac{0.01988 T_{S C}}{T_{r} p_{S C}} \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$	$\frac{0.01988 T_{S C}}{T_{r} p_{S C}} \frac{k_{g} h}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{3}{4} + S}$
IPR	$q_{g} = \frac{0.01988 T_{S C}}{T_{r} p_{S C}} \frac{k_{g} h [m (\bar{p}) - m (p_{w f})]}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{1}{2} + S}$	$q_{g} = \frac{0.01988 T_{S C}}{T_{r} p_{S C}} \frac{k_{g} h [m (\bar{p}) - m (p_{w f})]}{l o g_{e} (\frac{r_{e}}{r_{w}}) - \frac{3}{4} + S}$

Table 7.02g: Stabilized Inflow Performance Relationships for Gas Wells (previously Table 5.01g)
The Rawlins and Schellhardt Backpressure or Deliverability Equation^[1]
	Steady-State Flow Regime	Pseudo Steady-State Flow Regime
IPR	$- - -$	$q_{g} = C {({\bar{p}}^{2} - p_{w f}^{2})}^{n}$

As we saw in Lesson 6, the well hydraulics in the tubing is dependent on the production rate. For single-phase flow, this dependency was shown in the Darcy-Weisbach Equation (formerly Equation 6.12):

q = 411.147 E e f f D_{I D}^{2.5} {\frac{g c}{f D W ρ Δ l} [(p 1 - p 2) - \frac{g ρ}{144 g} (z 1 - z 2)]}^{0.5}

Equation 7.02

and for multi-phase flow was illustrated during our discussion on the multi-phase flow correlations (see Table 6.04). In that lesson, we discussed topics, such as:

Multi-Segmented well modeling
Pressure Traverse Curves, PTC
Tubing Performance Curves, TPC

A hypothetical tubing performance curve for a 2.0 inch outer diameter (O.D. – remember, the I.D. of the tubing controls the pressure drop, but by convention we quote the tubing size by its outer diameter, O.D.) tubing is shown in Figure 7.21. In the legend of this figure, we see some of the static and dynamic properties that impact tubing performance (see Table 6.04). In particular, we can see the wellhead pressure, $p_{W H}$ , is 100 psi in this example/figure. This wellhead pressure would be the pressure on the gauge of the wellhead shown in Figure 7.13. The flowing well pressure, $p_{w f}$ , in this figure is the solution of the well hydraulics equations (Darcy-Weisbach Equation or multi-phase flow correlation) which represents the pressure at the bottom of the tubing string (y-axis on this plot) that is required to lift the reservoir fluids at a given production rate (x-axis on this plot).

Note, that we can rearrange Equation 7.01 and solve for $p_{w f}$ :

p_{w f} = p - \frac{q}{P I}

Equation 7.03

This is the equation for a straight line in $q$ with a slope of $- \frac{1}{P I}$ and a y-intercept of $p$ The pressure, $p$ , acting as the y-intercept is the average pressure in the reservoir (for pseudo-steady state flow) and would slowly drift downward as the reservoir pressure is depleted with production. For multi-phase flow, we would not get a straight line, but a curve. For our straight-line example, the IPR is the red line in Figure 7.21. The Inflow Performance Relationship (IPR) represents the rate that fluids can be supplied from the reservoir at a given flowing pressure, while the Tubing Performance Curve, TPC, represents the rate that fluids can be received by the tubing and lifted to the surface at a 100 psi $p_{W H}$ . The intersection of these two curves, then, represents the operating point for the well at this wellhead pressure.

Figure 7.21: Inflow Performance Relationship (IPR), Tubing Performance Curve (TPC), and Operating Point for a Well

If we were to build a well hydraulics model for a well to run sensitivities on the tubing size, then a plot such as Figure 7.22 would result. When I say “… build a well hydraulics model …”, this model can be a simple as a hand calculation model^[4] (the industry standard method thirty years ago), an Excel spreadsheet model, or a current generation software model. The details to include in such a model depend on the objectives of the model. Any well model built with an objective of aiding in the completion design would need to include any pressure losses associated with the completion (for example, pressure drop due to flow through the gravel pack, flow through the perforations, or flow through a hydraulic fracture). We will discuss some of these additional pressure drops later in this lesson.

For sizing the tubing of the well, we would simply be able to calculate the $Δ q's$ associated with going from one tubing size (O.D.) to the next incremental tubing size (O.D.), run the economics to determine if the larger, more expensive tubing size would pay for itself with its incremental production rate (meet corporate economic hurdles), and continue until we found a tubing size (O.D.) that was uneconomic or could not physically fit inside our production casing.

One example that we can use for estimation of the tubing size is the payback time for an incremental increase in the tubing size. The payback time is the time period required to recoup an investment (or, in other words, the time period that the investment ties up our money). If the incremental rate from the IPR-TPC analysis shown in Figure 7.22 is $Δ q_{o}$ (STB/day), the total incremental cost for increasing the tubing size is $Δ C_{T}$ ($), and oil price is $P_{o}$ ($/STB), then the payback time, $t_{P B}$ (days) is:

t_{P B} = \frac{Δ C_{T}}{P_{o} Δ q_{o}}

Equation 7.04

Figure 7.22: Inflow Performance Relationship and Tubing Size Sensitivities

In this equation, the numerator is the incremental cost of the larger tubing size in dollars, while the denominator represents the daily revenue of the incremental oil sales in $/day. If a detailed estimate of $t_{P B}$ is required, then we can allow the rate to change over time using the decline curve analysis methods discussed in Lesson 4 and Lesson 5 (rather than using a constant $Δ q_{o}$ based on stabilized rates).

Earlier, I used the phrase “… corporate economic hurdles …;” I can illustrate the concept of an economic hurdle with our definition of payback time, Equation 7.04. Perhaps the company that you work for dictates that all design aspects of the well must pay for themselves in one year or less; then, we could use the IPR-TPC analysis to determine the largest tubing size that yields a $t_{P B}$ from Equation 7.04 that meets this one-year threshold.

When sizing tubing, we must also be aware that there are other considerations to be evaluated. For example, if we plan to run logging tools on wireline or perform a through-tubing workover, then we would need to size the tubing so that the inner diameter, I.D., would be able to accommodate the physical dimensions of the tools that we plan to run plus any tolerances. From the tubing sizes used in this example, 2.0, 2.5, and 3.5 inch O.D., we can see that the dimensions used in oil and gas wells can be important design criteria for the tubing size selection.

[3] Rawlins, E.L. and Schellhardt, M.A. 1935. Backpressure Data on Natural Gas Wells and Their Application to Production Practices, 7. Monograph Series, U.S. Bureau of Mines.

[4] Brown, K.,E.: The Technology of Artificial Lift Methods (Vols. 1 – 4), Petroleum Publishing Co., Tulsa, O.K. (1977)

7.7: Well Stimulation

We can also use the Tubing Performance Curves and Inflow Performance Curves to aid in other decisions concerning the well design. When we complete a well, we may want to consider stimulating the well or applying artificial lift in the original completion design.

We briefly discussed well stimulation when we were discussing the skin factor, $S$ in Lesson 4 and Lesson 5. In these lessons, we saw that the skin factor is part of the definition of the productivity index, $P I$ (see Table 7.01 and Table 7.02) and is positive for damage and negative for stimulation.

We will use two simple models of skin to illustrate its use when considering well stimulation in the completion design. These two simple skin models are:

S = - l o g_{e} (\frac{x_{f}}{2 r_{w}})

Equation 7.05

and

S = (\frac{k}{k_{s}} - 1) l o g_{e} (\frac{r_{s}}{r_{w}})

Equation 7.06

Where:

$S$ is the skin factor, dimensionless
$x_{f}$ is the hydraulic fracture length, ft
$r_{w}$ is the well radius, ft
$k$ is the permeability of the reservoir, md
$k_{s}$ is the permeability of the stimulated zone, md
$r_{s}$ is the radius of the stimulated zone, ft

These two skin models are based on different idealizations of reservoir/well system which are shown in Figure 7.23.

Figure 7.23: Two Reservoir Idealizations for Development of Simple Skin Models. (Left) an effective well radius in the presence of a hydraulically fractured well, and (Right) a composite reservoir formed by two concentric radial zones.

Equation 7.05 uses the idealization of the fracture half-length, $\frac{x_{f}}{2}$ as an effective wellbore radius. This idealization is valid if the flow patterns in the reservoir are approximately radial away from the fracture. It is observed that typically after some time period, the flow patterns do establish themselves as radial. You can substitute this definition of skin into any of the inflow performance relationships in Table 7.01 or Table 7.02, perform some algebra, and see that the fracture half-length takes the place of the well radius in a well if there is no other skin in that well.

This definition of skin is applicable for the simple modeling of hydraulically fractured vertical wells. Obviously, this simple description of skin would not be applicable for very complex completions such as that shown in Figure 7.01 with multiple fracture stages. For simple completion designs, we can analyze hydraulic fracture treatments with different fracture lengths to determine the optimal fracture length for our well.

Equation 7.06 defines a skin facture in an equivalent, homogeneous drainage area (single-zone reservoir) that would give the same IPR (rate – drawdown pressure relationship) as our actual composite reservoir (two-zone reservoir). In an acid matrix stimulation treatment in formations susceptible to acid (such as carbonate reservoirs – limestones and dolomites), when we acidize the well, the acid travels out radially from the well increasing the permeability as it reacts with the formation. At some point, typically several inches away from the well, the acid is spent and no longer has any impact on the permeability. Therefore, if we start off with a homogeneous reservoir and inject acid into a susceptible formation, then we would create a composite reservoir similar to the one shown in Figure 7.22 (B). Equation 7.06 is called the Hawkins formula.

Note from Equation 7.06 that if we are increasing the permeability, $k_{s} > k$ then the skin factor is negative, signifying stimulation. Therefore, we can use this model of skin to analyze acid treatments with acid types and acid volumes (effective $r_{s}$ ) to determine the optimal acid treatment for our well.

Once we select the optimal tubing size, then we can use the effective skin factors from Equation 7.05 or Equation 7.06 in the IPR equation to perform our IPR-TPC analyses. This may take several iterations if the stimulation treatment design impacts the choice for the optimal tubing size. A typical IPR-TPC Analysis for different stimulation treatments (effective skin values), is shown in Figure 7.23. The payback time for the stimulation treatments can also be determined from Equation 7.04.

Figure 7.24: Inflow Performance Relationship Sensitivity of Effective Skins and Tubing Performance Curve

7.8: Artificial Lift

Another aspect of well design is the application of artificial lift. When no artificial lift is applied, we refer to the well as a Natural Lift Well or a Naturally Flowing Well (i.e., the higher reservoir pressure is capable of lifting the heavy liquids without any assistance). As the reservoir pressure depletes due to production or the density of the fluid column in the well increases due to increasing water production rates, then artificial lift may be required to produce the wells at economic rates.

Artificial lift refers to the application of pumps or gas injection to assist the lifting of the heavier reservoir liquids. These methods may be applied early in the life of the field or reservoir to enhance the economics of marginal wells or later in the life of the field or reservoir as subsurface conditions change. In addition to increasing the production rates of wells, due to the reduction in the flowing bottom hole pressures of wells, from Material Balance Considerations, artificial lift can also increase the total recovery from the reservoir.

There are several methods of artificial lift including:

beam pumps (Nodding Donkey, Sucker Rod Pump)
electrical submersible pumps (ESPs)
hydraulic pumps
progressive cavity pumps (PCP pump)
gas lift

We will only discuss two methods of artificial: ESPs and gas lift. The design of ESPs and gas lift systems can also be considered in the IPR-TPC analysis. To perform the analyses, a segmented well hydraulics model (discussed in Lesson 6) must be designed to generate the appropriate tubing performance curves for use in the analysis. This is done by adding Downhole Devices into our well model. A downhole device is a piece of oilfield equipment with known rate pressure-rate behavior. Current generation well hydraulics software has options for all common downhole devices including (but not limited to) downhole pumps, gas lift valves, chokes, sub-surface safety valves (SSSV), gravel packs, perforations, etc.

A well completion with a downhole ESP device is shown in Figure 7.24. There are two ways to generate the tubing performance curves for ESP wells/completions:

the horsepower conversion method
Pump Curve method (a pump curve is a series of curves including the pump head (pressure boost) versus capacity (flow rate), power input (horse power) versus capacity, and pump efficiency versus capacity – all plotted on the same graph). The pump curve method requires that the user supply a pump curve for a specific pump to the model and the software iteratively determines the pressure boost and temperature change for the prevailing well conditions. This method is more accurate than the horsepower conversion method because the pump efficiency is a function of the capacity but is iterative.

I am including the links to a PetroWiki article and a Schlumberger Oilfield Review article on Electric Submersible Pumps.

PetroWiki ^[5]: Electrical Submersible Pumps [10]
Schlumberger Oilfield Review: Defining Electrical Submersible Pumps [11] ^[6]

The Schlumberger Oilfield Review link (second link) provides a simple schematic of an ESP (Figure 1 in the article) and an example of a pump curve (Figure 2 in the article).

The horsepower conversion method is a simple method to implement because it is non-iterative, so we will continue our discussion using this method. In this method, the pressure boost through the pump (difference between the outlet and inlet pressures) and the temperature change of a fluid going through the pump are defined by:

Δ p = \frac{942.86 P_{H P} ρ_{m} E_{e f f}}{q_{m}}

Equation 7.07

and

Δ T = \frac{0.185 Δ p (1 - E_{e f f})}{ρ_{m} U_{m} E_{e f f}}

Equation 7.08

Where:

942.86 and 0.185 are equation constants
$Δ p$ is the pressure boost from the pump, psi
$Δ T$ is the temperature increase through the pump, ºF
$P_{H P}$ is power rating of the pump (power is the rate of work, +W, in Figure 7.24), horsepower
$ρ_{m}$ is the density of the well fluids (mixture), lb_m/ft³
$E_{e f f}$ is the pump efficiency (assumed constant in the horsepower conversion method), dimensionless
$q_{m}$ is the total production rate of the well fluids (mixture) at the pump height, bbl/day
$U_{m}$ is the specific heat of the fluid, BTU/(lb_m-ºF)

Figure 7.25: Well Completion with an Electric Submersible Pump

Figure 7.25 shows a typical Inflow Performance Relationship – Tubing Performance Curve for ESP Optimization and Design. Typically, when optimizing ESPs, we evaluate:

the size of the pump (horsepower rating)
the number of pump stages
the depth of the pump

Figure 7.26: Inflow Performance Relationship Effective Skin Sensitivities and Tubing Performance Curve

Gas lift is an artificial lift method in which we install Gas Lift Valves in the tubing to inject gas into the flowing well stream. The lift gas injected is injected down the annulus and enters the tubing through the gas lift valves. The objective of introducing the external gas into the well stream is to lighten the well column.

I am including the link to the PetroWiki ^[5] article on Gas Lift:

PetroWiki: Gas Lift [12]

This article contains more details on gas lift than I am covering in the course lessons including discussions on two variants of gas lift: continuous gas lift and intermittent gas lift.

A typical completion with gas lift valves is shown in Figure 7.26. The gas lift device in a well hydraulics model would simply be the gas lift injection rate of the valve against the backpressure of the produced fluids. The Inflow Performance Relationship – Tubing Performance Curve for Gas Lift Optimization and Design looks like the one illustrated in Figure 7.25. When optimizing the gas lift design, the parameters that are typically investigated include:

the gas lift rate
the placement of the gas lift valves (particularly the bottom valve)

Figure 7.27: Well Completion with Gas Lift Valves

[5] Society of Petroleum Engineers technology website: PetroWiki [6]

[6] Rick, von Flatern: “Electrical Submersible Pumps,” Oilfield Review, Schlumberger (2015)

7.9: Key Learnings

The overriding well design considerations are:
- well costs
- tubing and completion longevity
- well simplicity and reliability
- ability to achieve all (or most) of the objectives of the well
Well objectives determine how a specific well should be designed. Several more common well objectives include:
- sand control for reservoirs made up of unconsolidated reservoir rock or rock susceptible to Fines Movement (movement of fine-grained materials within the rock)
- zonal isolation for reservoirs with multiple zones (to allow each individual zone to be shut in, if required)
- well stimulation for reservoirs with low permeability or susceptible to well damage
- artificial lift for low rate wells
Five common well design considerations are:
- well orientation
- completion design
- tubing size
- artificial lift
- well stimulation
Three common well orientations for crude oil and natural gas production are:
- vertical wells
- deviated (or slanted) wells
- horizontal wells
These well orientations have different applications in field development including costs and the avoidance of surface locations that are costly, environmentally sensitive, unsafe, or lack appropriate infrastructure (road access, water sources, etc.).
The well completion is defined as the portion of the well that connects the reservoir to the tubing. Three common forms of a well completion are:
- an open-hole or bare foot completion
- a screen or liner completion
- a cased and perforated (a cased and perf’ed) completion
Sand control is required in wells producing from unconsolidated or weakly cemented reservoir formations. It is required because fines movement caused by the pressure drop (drawdown) in the reservoir and fluid production dragging loose rock material and debris to the well. Production of this loose material may accumulate in the well as sand fill which may cause production, logging, and workover problems for the well.
Sand is controlled in the well design through the well completion. The most common form of sand control is some form of gravel pack:
- gravel pack (with slotted liner or screen)
- pre-packed liner
- pre-packed screen
- frac-pack
Unwanted fluid production is defined as the production of fluids other than the fluid(s) for which the well is designed. This may include gas and water from oil wells or water from gas wells. The well is typically designed for the fluid(s) that achieve the highest revenues from the well. Unwanted fluid production may come from:
- lateral fluid migration through the reservoir
- downward coning of gas from a primary or secondary gas cap or upward coning of water from a bottom-water reservoir
- injection from offset injection wells
Unwanted fluid production is controlled in the well design by a well completion with zonal isolation. By far, the most versatile well completion for zonal isolation is a cased and perforated well completion. Zonal isolation in a cased and perforated well may be controlled with (amongst others):
- packers
- bridge plugs
- sliding sleeves
Multiple well completions may achieve the desired zonal isolation (i.e., there is no unique well completion for a well). The overriding well design considerations (first bullet point above) are used to select the final well completion.
Tubing is the conduit for fluids from the completion to the surface. The flow of fluids up the tubing is governed by well hydraulics in the form of a Tubing Performance Curve.
Plotting the Inflow Performance Relationship (IPR) on the same graph and the Tubing Performance Curve (TPC) is the foundation of nodal analysis. The IPR defines the rate of fluid production from the reservoir at a given flowing pressure, p wf while the TPC defines the that the rate that fluids can be “pushed up” the tubing at the same flowing pressure. The intersection of these two relationships defines the operating point of the well at the current reservoir and tubing conditions. The Inflow Performance Relationship – Tubing Performance Curve analysis (nodal analysis) provides a powerful tool for defining the appropriate:
- tubing size
- well stimulation treatment
- artificial lift requirement

7.10: Summary and Final Tasks

Summary

In this lesson, we discussed five key design aspects for oil and gas wells considered by production engineers:

well orientation
well completion
tubing size
well stimulation
artificial lift

In addition, we discussed two common problems with well production: sand production from unconsolidated reservoir formations and production of unwanted fluids. The sources of unwanted fluid production are:

lateral fluid migration through the reservoir
downward coning of gas from a primary or secondary gas cap or upward coning of water from a bottom-water reservoir
injection from offset injection wells

We also saw that we could mitigate these two problems (sand production and unwanted fluid production) with proper well completions. For sand production, the most commonly used completion involves some form of a gravel pack where the gravel acts as a filter against the sand production. For unwanted fluid production, we build zonal isolation into our well completion designs. For these wells, we can use cased and perforated completions, along with systems of packers, bridge plugs, and sliding sleeves to provide zonal isolation to prevent production of unwanted fluids.

For determining the proper tubing size to use in a well, we plotted the Inflow Performance Relationship and the Tubing Performance Curve on the same graph. The intersection of these curves represents the operating point of the well. By testing multiple tubing strings, we can evaluate the impact of tubing size on the operating point of the well and determine those tubing strings that meet our economic hurdles.

Finally, we discussed well stimulation and artificial lift. We saw that the same analysis method could be used for these aspects of the well design. When evaluating well stimulation, we modified the Inflow Performance Relationship with simple skin models to evaluate the impact on the operating point; while for artificial lift, we saw that pump or gas lift devices had to be incorporated into the well hydraulics model to generate the appropriate Tubing Performance Curves for evaluation and optimization in our analyses.

Final Tasks

Complete all of the Lesson 7 tasks!

You have reached the end of Lesson 7! Double-check the to-do list on the Lesson 7 Overview page [13] to make sure you have completed all of the activities listed there before you begin Lesson 8.