DEVELOPMENT OF A GAS CONDENSATE RESERVOIR

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ABSTRACT

Gas condensate reservoirs are single phase at the initial condition. It changes to multiphase when the reservoir conditions are located between the critical point and the cricondentherm of the reservoir in the phase envelope. This makes it unique to providing a reliable source of energy for human usage.

The objective of this study is to use a 3D compositional model of the Niger Delta field to evaluate the production of a gas condensate reservoir.

This study is integrated into two main segments; the reservoir and fluid pressure, volume and temperature (PVT) model followed by reservoir simulation studies. The simulation involves running several development scenarios using the 3D compositional model of the Niger Delta field to optimize the recovery from the reservoir of interest.

Two vertical and horizontal wells were drilled in the model to study the production of the gas condensate reservoir using two development methods; natural depletion and gas cycling to maintain the reservoir pressure. Production of the gas condensate reservoir by maintaining a higher reservoir pressure through gas cycling maximized the hydrocarbon recovery.

Economic analyses carried out on the net present value (NPV) of the various production methods studied in this work, revealed that gas cycling with vertical wells proved to be economical as a result of higher cash flow and the effect of injection cost on the project profitability.

The results of this study gave further insights into the need to conduct detailed fluid PVT characterization and the importance of evaluating various reservoir optimization techniques in order to maximize recovery of oil from gas condensate reservoirs.

Keywords: Gas condensate, reservoir modeling, reservoir development methods, NPV analysis,compositional fluid characterization



CHAPTER 1

1.0         INTRODUCTION

1.1         Problem Definition

The global demand for fossil energy is increasing immensely because of high population and development. With the unbundling of the power sector in Nigeria, and the fact that the country currently suffers from energy poverty complicated by low oil price or oil price volatility, oil companies are looking for ways to minimize costs and increase productivity.

Nigeria has an estimated 180 trillion standard cubic feet of natural gas proven reserves, making it ninth in the world, and the largest in Africa (World Factbook, 2014) with about a 50/50 distribution ratio between Non-Associated Gas (NAG) and Associated Gas (AG). The Natural gas available in Nigeria could either be associated or non-associated. Associated gas refers to the natural gas found in association with oil within a reservoir, while reservoirs that contain only natural gas and no oil, have gas termed as non-associated gas.

Gas-condensate reservoirs represent a vital source of hydrocarbon reserves which have been recognized as a reservoir type, possessing the most complex flow and thermodynamic behaviors. Gas-condensate reservoirs are distinguished by producing both gas and condensate liquid at the surface. Retrograde condensate reservoirs produce gas to liquid ratios of about 3-150 MCF/STB (McCain, 1990), or condensate surface yields which range from 7 to 333 STB/MMCF. The condensate produced adds economic value in addition to gas produced, therefore making the condensate recovery a key consideration in the development of gas-condensate reservoirs. At greater depths during exploration, gas condensate reservoirs are encountered more often than other natural resources at higher pressure and temperature. This high pressure and temperature lead to a higher degree of degradation of complex organic molecules. As a result, the more the organic materials are buried deeper, the higher the tendency of the organic material to be converted to gas or gas condensate. These reservoirs have grown significantly as deeper depths are drilled to hit its targets, subsequently encountering very high temperatures and pressures which are necessary for their presence (Okporiri and Idigbe, 2014).

The typical pressure of a gas condensate reservoir is mostly above or close to critical pressure when discovered. Initially, the reservoir pressure is at a point that is above the dew-point curve, so the reservoir is in gaseous state and only at this time does single-phase gas exist . However as the production progresses, there is isothermal pressure decline and a liquid hydrocarbon phase where condensate is formed viz. when the bottom hole pressure in an existing flowing well falls below the dew-point of the reservoir fluid. The condensate accumulation tends to build up a liquid phase around the wellbore. It leads to a decrease in the effective permeability of gas into the wellbore. The low productivity associated with condensate buildup can be substantial.

1.2         Aim of the Research

To optimize the development of a new gas condensate reservoir through integrated dynamic reservoir simulation studies which will involve running several development scenarios. Maximize the recovery of oil from gas condensate reservoirs and ensure the provision of produced gas to maintain pressure.

1.3         Research Objectives

In order to achieve the above set goal, the following objectives will be considered:

1.      Develop a typical Niger Delta gas condensate dynamic reservoir model.

2.      Determine the impact of geometric and harmonic averaged permeability distribution on the condensate recovery.

3.      Determine the number of wells to be drilled to reach production objectives.

4.      Assess gas injection pressure maintenance options and its impact on recovery.

5.      Run the economics analysis of the project.

DEVELOPMENT OF A GAS CONDENSATE RESERVOIR

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Project Information

  • CATEGORY : PETROLEUM ENGINEERING
  • TYPE : PROJECT MATERIAL
  • FORMAT : MICROSOFT WORD
  • ATTRIBUTE : Documentation Only
  • PAGES : 50 Pages
  • CHAPTERS : 1 - 5
  • PRICE : ₦ 3,000.00

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The typical pressure of a gas condensate reservoir is mostly above or close to critical pressure when discovered. Initially, the reservoir pressure is at a point that is above the dew-point curve, so the reservoir is in gaseous state and only at this time does single-phase gas exist . However as the production progresses, there is isothermal pressure decline and a liquid hydrocarbon phase where condensate is formed viz. when the bottom hole pressure in an existing flowing well falls below the dew-point of the reservoir fluid. The condensate accumulation tends to build up a liquid phase around the wellbore. It leads to a decrease in the effective permeability of gas into the wellbore. The low productivity associated with condensate buildup can be substantial... petroleum engineering project topics

DEVELOPMENT OF A GAS CONDENSATE RESERVOIR