GAS LIFT OPTIMIZATION OF OIL-PRODUCING WELLS USING PROSPER NODAL ANALYSIS
ABSTRACT
In this study, the method of nodal analysis was employed to design the optimum well completion needed by a particular oil well (designated as C-05) located off the coast of the Niger Delta. Based on available data from the geometry and configuration of the well, as well as well test data, an analytical software, PROSPER, used for well design, modelling and performance calculations, was first used to calibrate the well i.e. model its behaviour. The well has an issue of increasing water cut which has a huge impact on oil production negatively. Using the calibrated model, sensitivity runs were carried out on suspected node that could help cub the problem, i.e. provide higher water cut that would still keep production rate within its economic limit and extend the well’s life. The software approach was based on the principles of Nodal analysis. This work shows the use of nodal analysis in predicting well performance and optimising a system.
TABLE OF CONTENT
Title Page………………..i
Certification………….…ii
Dedication………………iii
Acknowledgement……….iv
Table of content……...…v
Abstract.......................vi
CHAPTER ONE
1.0 Introduction
1.1 ARTIFICIAL LIFT
1.1.1TYPES OF ARTIFICIAL LIFT
1.2 GAS LIFT
GAS LIFT TYPES
CONTINUOUS FLOW GAS LIFT
INTERMITTENT FLOW GAS LIFT
1.1 Background of the study.
1.2 statement of the problem
1.3 Objectives of the study
1.4 scope of the study
1.5 Limitations of the study
CHAPTER TWO
LITERATURE REVIEW
Literature review
2.0 production system
2.1 Production optimization
2.2 Nodal analysis
2.3 Concept of the Nodal analysis approach
2.4 AUTHOR’S CONTRIBUTIONS
CHAPTER 3
METHODOLOGY
3.1. INTRODUCTION TO THE METHODOLOGY
3.2 DATA SOURCE AND DATA ANALYSIS
3.3 STATEMENT OF PROBLEM
3.4 CASE STUDY OBJECTIVES
3.5 PROSPER
3.6 OBJECTIVE 1: Simulate well X-05 performance by building a representative
(valid) model using PROSPER.
3.7 OBJECTIVE 2: Simulating Base Case forecast under various operating
conditions.
3.8 OBJECTIVE 3: Evaluating various development options to optimize oil
Production
CHAPTER 4
SYSTEM DATA, RESULTS AND ANALYSIS
4.1 OPTIONS
4.2 PVT DATA
4.3 IPR DATA
RESULTS
4.4 EQUIPMENT DATA
4.5 ANALYSIS SUMMARY
and many more.
4.5.1 SIMULATING BASE CASE FORECAST UNDER VARIOUS OPERATING
CONDITIONS.
4.5.2 EVALUATING VARIOUS DEVELOPMENT OPTIONS TO OPTIMIZE OIL
PRODUCTION
CHAPTER 5
CONCLUSION
5.1 RECOMMENDATION-
REFERENCES
CHAPTER ONE
1.0 Introduction
Hydrocarbons(oil and gas) are found in the pore spaces of sedimentary geologic formations (reservoir rocks). Once an oil or gas reservoir is discovered and assessed, production engineers begin the task of maximizing the amount of oil or gas that can ultimately be recovered from it. Some reservoir rocks may allow the oil and gas to move freely, making it easier to recover. Other reservoirs do not part with the oil and gas easily and require special technique to move the oil or gas from the pore spaces in the reservoir rock to a producing well. Even with today’s technology, in some reservoirs more than two-thirds of the oil in the reservoir may not be recoverable.
Optimum production of oil from an oil reservoir is the main objective or target of the operators of an oil well in order to meet up with the growing demands of the crude oil. The efficient production of fluids from a reservoir depends on the maintenance of the pressure draw down between the reservoir and the well bore which is the driving force or energy that forces the reservoir fluid (oil) from the reservoir into the wellbore.
The productivity of the system is dependent on the pressure loss which occurs in
several areas of the flow system namely:-
• The reservoir
• The wellbore
• The tubing string
• The choke
• The flow line
• The separator
Image
Fig 1: The production system.
Under natural flowing conditions the reservoir pressure
must provide all the energy to operate the system i.e. all the pressure drop in the system.
PR= ∆PSYSTEM + PSEP
where;
PR = reservoir pressure
∆PSYSTEM = total system pressure drop
PSEP = separator pressure
To maintain an optimum production rate from the well, the reservoir energy which is the pressure draw down between the wellbore and the reservoir must be maintained or sustained. The sustenance or maintenance of this energy (pressure draw down) depends on the reservoir drive mechanism.
1.1 ARTIFICIAL LIFT
Artificial lift is any process used to raise oil to the surface through a well after reservoir pressure has declined to the point at which the well no longer produces by means of natural energy.
At some time in the life of a well, the reservoir will no longer be able to flow naturally to the surface at the required rate. This may be due to:-
⦁ Insufficient pressure draw down between the reservoir and the well.
⦁ Dead wells which are as a result of pump kill fluid into them.
⦁ Increasing water-cut or production.
The above conditions have something in common; the hydrostatic gradient is higher than the pressure gradient. The reservoir’s natural energy must then be supplemented by some form of artificial lift.
(a) (b)
Fig 1.2 (a) IPR/VLP curve for a naturally flowing well, (b) IPR/VLP curves for a dead well.
1.1.1TYPES OF ARTIFICIAL LIFT
There are four basic ways of producing an oil well by artificial lift. These are:
1. Gas Lift
2. Sucker Rod Pumping
3. Submersible Electric Pumping
4. Subsurface HydraulicPumping
1.2 GAS LIFT
Gas lift is one of the artificial lift method used in the industry to supplement the reservoir energy for continued production of oil. Gas lift is either a continuous or intermittent process whereby gas is injected into the well to reduce the density of the produced fluid. This has the effect of reducing the static head in the tubing thereby assisting the flow of fluid from the reservoir through the tubing to the well head.. The technology (gas lift) has been used to produce oil and gas from wells with low reservoir pressure by reducing the hydrostatic pressure in the tubing. Gas is injected into the tubing as deep as possible and mixes with the fluid from the reservoir. Gas lifting is considered to be one of the most flexible and cost-effective artificial lift systems. The optimum level of production rates versus lifting depth achieved for this system is unmatched (Eikrem et al, 2002). This system is best used for highly deviated wells producing sand, for wells with high formation of gas and liquid ratios, and for wells with multiple completions (Brown et al, 1980). Thus, optimizing production levels for these wells is one of the most important concerns of oil and gas companies. As oil wells mature, engineers face bigger challenges in recovering oil. One of the most common techniques used for improving crude oil production is through gas lifting. Because of its low operating cost and flexibility of production that it provides, many companies are involved with this system as it accounts for some reasonable proportion of oil production as evident from table 1. However, several factors limit the effectiveness of gas lifting, as different reservoirs are faced with variable pressure levels, temperature, and depositions. Therefore, as operations take place, the need for continuous system design, diagnosis, and troubleshooting arises in order to optimize production levels.
GAS LIFT TYPES
There are two basic types of gas lift systems used in the oil industry.
These are;
⦁ Continuous flow gas lift
⦁ Intermittent flow gas lift
CONTINUOUS FLOW GAS LIFT
In the continuous flow gas lift process, relatively high pressure gas is injected downhole into the fluid column. This injected gas joins the formation gas to lift the fluid to the surface by one or more of the following processes:
1. Reduction of the fluid density and the column weight so that the pressure differential between reservoir and wellbore will be increased
2. Expansion of the injection gas so that it pushes liquid ahead of it which further reduces the column weight thereby increasing the differential between the reservoir and the wellbore.
3. Displacement of liquid slugs by large bubbles of gas acting as pistons.
If the lower flowing pressure gradient reduces the flowing bottomhole pressure (BHFP) to establish the drawdown required for attaining a design production rate from the well. If sufficient drawdown in the bottomhole pressure (BHP) is not possible by continuous flow, intermittent gas lift operation may be used.
fig 1-3 continuous gas lift installation.
INTERMITTENT FLOW GAS LIFT
This operates on the principle of intermittent gas injection. Gas lift injection occurs for a certain length of time and then stops. After a period of time has elapsed, injection again takes place and the cycle is repeated. In the intermittent flow system, fluid is allowed to accumulate and build up in the tubing at the bottom of the well.
The frequency of gas injection in intermittent lift is determined by the amount of time required for a liquid slug to enter the tubing. The length of the gas injection period depends on the time required to push a slug of liquid to the surface.
Gas lift is essentially an extension of natural flow, whereby the producing GOR (gas oil ratio) is artificially increased by the injection of gas. The requirement of gas lift is often a result of either an increased water cut or a declining reservoir pressure.
For maximum benefit, the gas should be injected as deep as possible, reducing the density of the fluid column as much as possible. Gas is injected through gas lift valves, a series of which are run inside pocket mandrels together with the tubing string, and so designed that only one valve is open and passing gas at any one time.
Image
Fig 1-4 Intermittent gas lift installation.
1.1 Background of the study.
Before a well can produce oil or gas, a borehole is drilled from the surface to the oil and gas pool or reservoir rock. The borehole must be stabilized with casings cemented in place. A small diameter tubing string is centered in the wellbore and is sometimes held in place with packers. This tubing will carry the oil and gas from the reservoir to the surface. Reservoirs are typically at elevated pressure because of the underground forces that surrounds them. The driving force which causes these fluids to move out of the reservoir comes from the compression of the fluids that are stored in the reservoir. The actual energy that causes a well to produce oil results from a reduction in pressure between the reservoir and the producing facilities on the surface. Early in its production life, the underground pressure will often push the hydrocarbons all the way to the surface facilities. Depending on reservoir conditions, this “natural flow” may continue for many years. The production capacity of an oil well is a key surveillance factor in monitoring the well’s performance which is dependent on a number of other factors which include; fluid properties and composition of the oil itself, gas oil ratio, water cut, reservoir characteristics and completion strategy/design (Beggs et al, 1991). The well performance consists of the inflow performance relationship (IPR) which involves flow from the reservoir into the wellbore and the outflow performance which involves flow from the wellbore up the tubing to the surface production facilities. Constant monitoring of the well performance is of paramount importance in the oil and gas industry as it is critical to the crude oil production obtainable from such wells and the equivalent profit margins that will be generated from the production (Hernandez et al, 2001). Monitoring of the well’s performance also help the engineer to determine the economic limit and amount of oil production recoverable from such wells. Once a well is produced down to its economic limit due to pressure depletion, increase in water-cut the pressure differential which is the driving energy becomes insufficient in producing the fluid (oil) to the production facilities
(Beggs et al, 1991). Gas lift method once applied at the required injection gas rate can supplement the reservoir energy to drive the oil to the surface.
The introduction of lift gas to a non-producing or low producing well is a common method of artificial lift. Naturalgas is injected at high pressure from the casing into the wellbore and mixes with the produced fluids from the reservoir . The continuous aeration process lowers the effective density and therefore the hydrostatic pressure of the fluid column, leading to a lower flowing bottom-hole pressure (Pbh). The increased pressure differential induced across the sand face from the in situ reservoir pressure (Pr), given by (Pr − Pbh), assists in flowing the produced fluid to the surface. The method is easy to install, economically viable, robust, and effective over a large range of conditions, but does assume a steady supply of lift gas. At a certain point, however, the benefit of increased production due to decreased static head pressure is overcome by the increase in frictional pressure loss from the large gas quantity present. This has the effect of increasing the bottom-hole pressure andlowering fluid production.
1.2 statement of the problem
Movement or transport of oil to the production facilities requires energy to overcome friction losses in the systems and to lift the products to the surface. The production system can be relatively simple or can include many components in which energy or pressure losses occur.
The production rate or deliverability of a well can often be severely restricted by the performance of only one component in the system due to pressure losses. As mentioned earlier, within the life of a reservoir, there is a time when the available reservoir pressure is unable to lift the produced fluid to the surface. This is mainly as a result of pressure depletion , increased water production (water cut). Also, the need may arise for producing companies of oil and gas to maximize the production of oil and gas at the current installation facilities and reservoir condition. Most times, the efforts of the companies are directed to a medium and long term project to maximize the factor of recovery (production of oil to the minor possible cost), and in the short term to accelerate the recovery of the recoverable reservations. These efforts are usually realized during the economic limit period of the well in which the energy for production (pressure draw down) is insufficient for the required production rate. It becomes necessary to optimize the production system of the well to increase the economic recovery and to meet up with the increasing global energy demands.
1.3 Objectives of the study
As discussed earlier, the producing capacities of oil wells reduces as the oil field matures (function of time) due to the combined effects of interrelated factors that affects the well’s performance and economic recovery. To address this issue, optimization of the well (production system ) becomes necessary to maximize the well’s production.
One of the most used techniques for optimizing the oil production systems, considering its verified effectiveness and worldwide level trust worthiness is the Nodal analysis (Beggs et al, 1991). In order to optimize the production system using this technique, it is necessary describing the production system, making emphasis on the components of the production system in order to determine the production capacity of the well. The Nodal analysis allows to evaluate the performance of a completions of production, calculating the relation of the flow of production and the pressure drop that will occur in all its components, allowing to determine the flow of oil or gas that can produce a well bearing in mind the geometry of the perforation and increasing the rate of production to a low cost. Though gas lift optimization will always improve the production capacity, there is a need to identify the gas injection rate and tubing size that will lead to a maximum production from the well.
The project will aim to identify the factors and parameters that affect the well’s performance.
The project will aim to apply the Nodal analysis technique in simulating flow and analyzing the production system of a naturally flowing well and identifying the pressure losses in the producing system.
The project will also aim to design a gas lift system (model) for the naturally flowing well and optimizing the production system to improve the production system via the gas lift system model.
In addition to these, this work will aim to compare the results in terms of production capacity (production rate) for a naturally flowing well and the optimized results of the gas lifted well.
1.4 scope of the study
The study involves the collection of well, reservoir, completion and well test data (and other relevant data) to build a well model in order to characterize the well.
The following points highlight the scope of this study:
⦁ Designing of a well model that will serve the purpose of this study using relevant input data.
⦁ Appropriate selection of the best correlations available in the Prosper nodal analysis software that will aid in a more accurate performance prediction and matching of the well data.
⦁ Generating the inflow performance relationship (IPR) of the well model to characterize the well’s performance.
⦁ Generating the vertical lift performance (VLP) of the well’s model to characterize the outflow performance of the well.
⦁ Matching the IPR and VLP curve to determine the optimum flow condition of the well at the current reservoir pressure.
⦁ Validating the well model with the help of available well test data.
⦁ Using the validated well model to run a sensitivity analysis and prediction to investigate the effects of different parameters on the well performance.
⦁ Designing a gas lift system for the well model.
⦁ Perform a sensitivity analysis and prediction study as part of the optimization process.
⦁ Comparing the optimized results derived from the gas lifted well model and the natural flowing well.
This will help meet the objectives of this study and also examine the results of optimizing production from the well. The predictions of different parameters that are critical to the performance of the reservoir system will also be analyzed.
1.5 Limitations of the study
During the course of this study, some limitations were highlighted and assumptions made. This was done so as to achieve the goal of this project by idealizing the study/model.
These limitations include:
⦁ Multiphase fluid flow problems along the tubing.
⦁ Ability of the well to deliver a stable flow rate which can impose additional restrictions on the achievable flow rate.
⦁ Well instability.
.