Investigation Of Appropriate Time To Terminate Augmented Gas Flooding For Saturated Reservoir

Description

ABSTRACT

One of the most accepted and widely used technologies for enhanced oil recovery is injection of gas or solvent that is miscible or near miscible with reservoir oil. Understanding gas flooding requires a good understanding of the interaction of phase behavior and flow in the reservoir, and how oil and gas develop miscibility.

The development of natural gas in tight sandstone gas reservoirs via CH₄-CO₂ replacement is promising for its advantages in enhanced gas recovery (EGR) and CO₂ geologic sequestration. However, the degree or time of recovery and the influencing factors of CO₂ flooding for enhanced gas recovery as well as the CO₂ geological rate are not yet clear. In this study, the tight sandstone gas reservoir characteristics and the fluid properties of the Sulige Gasfield were chosen as the research platform. Tight sandstone gas long-core displacement experiments were performed to investigate (1) the extent to which CO₂ injection enhanced gas recovery (CO₂-EGR) and (2) the ability to achieve CO₂ geological storage. Through modification of the injection rate, the water content of the core, and the formation dip angle, comparative studies were also carried out. The experimental results demonstrated that the gas recovery from CO₂ flooding increased by 18.36% when compared to the depletion development method. At a lower injection rate, the diffusion of CO₂ was dominant and the main seepage resistance was the viscous force, which resulted in an earlier CO₂ breakthrough. The dissolution of CO₂ in water postponed the breakthrough of CO₂  while it was also favorable  for improving the gas recovery and CO₂ geological storage. However, the effects of these two factors were insignificant. A greater influence was observed from the presence of a dip angle in tight sandstone gas reservoirs. The effect of CO₂ gravity separation and its higher viscosity were more conducive to stable displacement. Therefore, an additional gas recovery of 5% to 8% was obtained. Furthermore, the CO₂  geological storage exceeded 60%.  As a consequence,  CO₂-EGR was found to be feasible for a tight sandstone gas reservoir while also achieving the purpose of effective CO₂ geological storage especially for a reservoir with a dip angle.

TABLE OF CONTENTS

COVER PAGE

TITLE PAGE

APPROVAL PAGE

DEDICATION

ACKNOWELDGEMENT

ABSTRACT

CHAPTER ONE

• INTRODUCTION
• OBJECTIVE OF THE STUDY
• PROBLEM STATEMENT

2.2      HISTORICAL BACKGROUND OF THE OIL WELL

2.3       LIFE OF A WELL

2.4    TYPES OF WELLS

2.5       WELLS PERFORMANCE CHAPTER TWO

LITERATURE REVIEW

• OVERVIEW OF OIL WELL

2.6        INFLOW PERFORMANCE RELATIONSHIP

2.7      VERTICAL LIFT PERFORMANCE

2.8      PRODUCTIVITY INDEX

2.9       GAS LIFT SYSTEM

2.10    GENERAL CLASSIFICATION OF GASLIGHT

2.11    PRINCIPLE OF GASLIGHT

2.12      ADVANTAGES AND DISADVANTAGES OF GAS LIFT

CHAPTER THREE

• METHODOLOGY

3.2     PVT MATCHING

3.3     VLP/IPRMATCH

CHAPTER FOUR

4.1      RESULT ANALYSIS

4.2      MONTE CARLO (RESERVE ESTIMATION)

4.3      SENSITIVITY ANALYSIS

4.4    WELLHEAD PRESSURE

4.5     WATER CUT

4.6     CONDENSATION GAS RATIO

CHAPTER FIVE

• CONCLUSION

REFERENCES

CHAPTER ONE

1.0                                          INTRODUCTION

“Gas flooding” typically using CO₂, N₂, or air has become one of the leading enhanced oil recovery (EOR) technologies for residual oil development in conventional reservoirs [1–4]. Unfortunately, “gas flooding” for natural gas reservoirs is currently only in the research and development stage. Tight gas reservoirs are one of the most important areas of unconventional natural gas exploration and development in the world and they have rich resource reserves [5]. However, a tight gas reservoir is characterized by poor reservoir properties, strong heterogeneity, and complicated pore-throat structures. The main traditional method for gas recovery is depletion development, but the recovery is only approximately 35% [6,7]. In order to increase recovery from tight gas reservoirs, a new method of enhanced gas recovery (EGR) is urgently required. The phase state of CO₂ is easily transformed into the supercritical state [8–10] when the temperature exceeds the critical temperature (31.26 ◦C) and the pressure exceeds the critical pressure (7.29 MPa). Due to tight/shale gas reservoirs generally having great depths, it is easy for CO₂ to reach the supercritical state if it is injected into these reservoirs. Theoretically, supercritical CO₂ effectively displaces the natural gas and improves gas recovery in tight/shale gas reservoirs due to its higher density, higher viscosity, and lower diffusion rate.

There have been a substantial number of detailed investigations on gas adsorption characteristics in recent years, which aim to understand the mechanism of CH₄ displacement by CO₂ in coal reservoirs. Littke [11] studied the adsorption and desorption abilities of CO₂ and CH₄ under various temperature and pressure conditions. The adsorption capacity of CO₂ was higher when compared to CH₄. Liang [12] experimentally investigated the displacement mechanism underlying the driving out of coal-bed methane by gaseous CO₂ and discovered that the permeability of CO₂ was beyond two orders of magnitude higher when compared to CH₄. This result was explained by the differences in the physical properties of the two gases, which are combined with the competitive adsorption effect. Zeng [13] theoretically established an internally consistent adsorption-strain-permeability model to describe the adsorption capacity of coal reservoirs to CH₄ and CO₂ and the displacement process of CH₄  by CO₂.  The results indicated that the adsorption capacity of CO₂  was two to five times that  of CH₄. In general, CO₂ is chosen for injection into tight sandstone gas reservoirs to achieve EGR based on the following aspects. First, CH₄ in tight gas reservoirs primarily exists in an adsorbed state and CO₂ has a stronger adsorption capacity than CH₄ under the same conditions [14,15]. Second, since the mixing speed of CO₂ and CH₄ is slower when compared to pressure recovery, the injection of CO₂  can increase the formation pressure and displacement pressure gradient.  Consequently,   the flow velocity increases, which effectively gathers and drives the flow of CH₄ in the reservoirs [16]. Moreover, the maintenance of pressure can also provide pressure support to prevent the formation of subsidence and water invasion [17]. In addition, injecting CO₂ into tight sandstone gas reservoirs not only can achieve the purpose of EGR but also realize CO₂ geological storage, which is of great significance for mitigating the global greenhouse effect [18,19]. For the previously mentioned reasons and the fact that CO₂ flooding can increase coal seam recovery, CO₂ flooding is feasible for EGR from tight sandstone gas reservoirs, theoretically. According to reports, only three pilot projects have existed globally [20,21]. CO₂ storage pilot experiments were carried out in three gas fields including Beihai K12-B in Holland [22], Budafa in Hungary [23], and Algeria [10], but all were mainly concerned with achieving CO₂ geological storage. CO₂-EGR is widely utilized in medium-permeability and high-permeability gas reservoirs both domestically and overseas while experimental studies on CO₂-EGR in tight sandstone gas reservoirs have rarely been reported.

1.1                            BACKGROUND OF THE STUDY

A variety of gases can and have been used for immiscible gas displacement, with lean hydrocarbon gas used for most applications to date. Historically, immiscible gas injection was first used for reservoir pressure maintenance. The first such projects were initiated in the 1930s and used lean hydrocarbon gas (e.g., Oklahoma City field and Cunningham pool in the US^[1] and Bahrain field in Bahrain^[2][3]). Over the decades, a considerable number of immiscible gas injection projects have been undertaken, some with excellent results and others with poor performance.

Gas injection projects are undertaken when and where there is a readily available supply of gas. This gas supply typically comes from produced solution gas or gas-cap gas, gas produced from a deeper gas-filled reservoir, or gas from a relatively close gas field. Such projects take a variety of forms, including the following:

• Reinjection of produced gas into existing gas caps overlying producing oil columns.
• Injection into oil reservoirs of separated produced gas for pressure maintenance, for gas storage, or as required by government regulations.
• Gas injection to prevent migration of oil into a gas cap because of a natural waterdrive, downdip water injection, or both.
• Gas injection to increase recoveries from reservoirs containing volatile, high-shrinkage oils and into gas-cap reservoirs containing retrograde gas condensate.
• Gas injection into very undersaturated oil reservoirs for the purpose of swelling the oil and hence increasing oil recovery.

The primary physical mechanisms that occur as a result of gas injection are:

1. Partial or complete maintenance of reservoir pressure
2. Displacement of oil by gas both horizontally and vertically
3. Vaporization of the liquid hydrocarbon components from the oil column and possibly from the gas cap if retrograde condensation has occurred or if the original gas cap contains a relict oil saturation
4. Swelling of the oil if the oil at original reservoir conditions was very undersaturated with gas

Gas injection is particularly effective in high-relief reservoirs where the process is called “gravity drainage” because the vertical/gravity aspects increase the efficiency of the process and enhance recovery of updip oil residing above the uppermost oil-zone perforations.

This page discusses gas injection into oil reservoirs to increase oil recovery by immiscible displacement. The use of gas, either of a designed composition or at high-enough pressure, to result in the miscible displacement of oil is not discussed here; for a discussion of that topic, see Miscible injection enhanced oil recovery (EOR).

1.2                               OBJECTIVE OF THE STUDY

Oil recovery from heavy oil resources has always been a challenging task. This work is aimed at investigating the recovery efficiency of gas-augmented low salinity gas flooding in heavy oil reservoirs.

1.3                                   SCOPE OF THE STUDY

In this work, the reservoir characteristics and fluid properties of the Sulige Gasfield were chosen as the research platform while displacement experiments using combined natural long-cores were performed to investigate the variables affecting CO₂-EGR. The extent of CO₂-EGR and CO₂ geological storage was measured by using various injection rates,  dry and aqueous cores,  and formation     dip angles.   In this scenario,  the feasibility of CO₂-EGR in tight sandstone gas reservoirs using     the displacement mechanism is examined and the geological  storage  of  CO₂  is  also  discussed and explained.

1.4                             APPLICATION OF THE STUDY

The decision to apply immiscible gas injection is based on a combination of technical and economic factors. Deferral of gas sales is a significant economic deterrent for many potential gas injection projects if an outlet for immediate gas sales is available. Nevertheless, a variety of opportunities still exist. First are those reservoirs with characteristics and conditions particularly conducive to gas/oil gravity drainage and where attendant high oil recoveries are possible. Second are those reservoirs where decreased depletion time resulting from lower reservoir oil viscosity and gas saturation in the vicinity of producing wells is more attractive economically than alternative recovery methods that have higher ultimate recovery potential but at higher costs. And third are reservoirs where recovery considerations are augmented by gas storage considerations and hence gas sales may be delayed for several years.

Nonhydrocarbon gases such as CO₂ and nitrogen can and have been used.^[4] In general, calculation techniques developed for hydrocarbon-gas injection and displacement can be used for the design and application of nonhydrocarbon, immiscible gas projects. Valuing the use of such gases must include any additional costs related to these gases, such as corrosion control, separating the nonhydrocarbon components to meet gas marketing specifications, and using the produced gas as fuel in field operations.