ASSESSMENT OF THE TECHNICAL BENEFITS OF DUAL GRADIENT DRILLING

CHAPTER ONE
INTRODUCTION
DGD is a technology that makes use of separate fluids with different densities in the wellbore. The lighter fluid floats on top of the heavy fluid in the riser. The lighter fluid is only used for inducing pressure and is otherwise inactive. However the heavy fluid is used for the same purpose as used in the conventional drilling procedures. This helps to adjust the bottom hole pressure (BHP) in a shorter time, and make it able to adjust the well bore pressure curves with the formation pressure curves. The attractions that DGD highlights are the reduction in the cost of drilling and an increase in the production rate after well completion ( Gaup, 2014).
The development work on the DGD was accelerated during the 1990s when a joint industry project was undertaken with the aim to utilize such technology to be used in the high pressure, low fracture gradient in ultra-deep waters. Even though sufficient investments have been made on drilling rigs which can operate in depths greater than 8000ft, the resources present at these reservoirs cannot be extracted unless new procedures are developed to lower hydrostatic mud pressures to avoid fractures in the shallow zones. The problems faced in ultra-deep drilling include shallow water flowing, lost circulation and loss of well control. If any of these problems occur, they will prevent the completion of the well to be achieved. Multiple casing strings are used to avoid such problems. This means that the production string is quite small for a high production well and also for horizontal and multilateral completions in order to make the project economically viable. Pumps are used to reduce the hydrostatic head from the mud-line to the surface in DGD techniques. This is the reason why there is no balanced u-tube present in DGD as compared to the conventional drilling ( Kennedy 2001). The primary component that enables the DGD operations is the Mud Lift Pump (MLP). With the help of diaphragm pumps powered by the seawater, it pumps the drilling fluid and cutting back to the rig floor. The Subsea Rotating Device (SRD) maintains the boundary between the sea water density fluid in the drilling riser and the drilling fluid and redirects the mud through the MLP through the Solids Processing Unit (SPU). SPU is used to decrease the size of the drill cuttings which can be managed by the MLP (Ganpatye et al. 2013).

ENGINEERING DESIGN AND PREDICTION OF HYDRATE FORMATION FOR A GAS PIPELINE

ABSTRACT

This research is focused on the difficulties that gas producers usually face with Hydrate formation during transportation. Hydrate build up in gas transportation flowlines is one of the major tasks for gas operators to deal with as it may cease gas flow through the pipeline, reduce well head measured flow rate, equipment damages e.t.c Two kinds of Engineering designs were developed to help transport gases of different pressures to an extension facility whose inlet pressures was designed at 8 barg. HYSYS VERSION 2006 was used for the simulation of these designs to check for the possibilities of Hydrate formation and recommendations were made based on the outputs.
Flow velocity is a very important criterion in determining the possibilities of noise in a gas transporting pipeline. There is a possibility of noise in a gas pipeline if the fluid mean velocity exceeds 60 ft/sec. Also, one of the objectives of this project is to verify the suitability of pipe lines sizes for the 8 barg pressure to transport gas over a distance of 120 km. For this project, a default pipe line size of 10” SCH 40 was selected and other pipe sizes lesser and greater than it were also used to pick the most suitable, simultaneously considering cost. PIPESIM VERSION 2009.1 was used for these analyses and the best pipeline size was determined.
The simulations reveal that both designs are efficient enough and at standard conditions, there will be no possibilities of hydrate formations but the possibilities of establishing design A will be recommended because it entails lower cost and less space is required. Also, a pipeline size of 10” SCH 40 will be sufficient for the given flow conditions but a pipe line size of 8” SCH 40 can also be used.

• TABLE OF CONTENTS

• CERTIFICATION ii

• DEDICATION iii

• ACKNOWLEDGEMENT iv

• ABSTRACT v

• LIST OF TABLES viii

• LIST OF FIGURES ix

• CHAPTER ONE 1

• 1.0 INTRODUCTION 1

• 1.1 Background Knowledge 2

• 1.2 Aims and Objectives of the Project 3

• 1.3 Justification 3

• 1.4 Scope of work 4

• 1.5 Problem Statement 4

• 1.6 Facilities Schematics 5

• CHAPTER TWO 7

• 2.0 LITERATURE REVIEW 7

• 2.1 Natural Gas Transportation through Pipelines 7

• 2.2 Single Phase Pipe Flow 8

• 2.2.1 General Pressure Drop Equations in Gas Flow 8

• 2.2.2 Simplified Equation 9

• 2.2.4 Panhandle Equation 11

• 2.2.5 The Spitzglass Equation 12

• 2.3 Flow Assurance 12

• 2.4 Natural Gas Hydrates 14

• 2.4.1 History of Natural Gas Hydrates 14

• 2.4.2 Structure of Natural Gas Hydrate 15

• 2.5 Flow Assurance Challenges and Control 18

• CHAPTER THREE 21

• 3.0 METHODOLOGY 21

• 3.1 System Description and Simulation Model 21

• 3.2 Basis of Design 23

• 3.2.1 Design Basis Feed Composition 23

• 3.2.2 Basis of Analysis 24

• 3.2.3 Bulkline 24 vii

• 3.2.4 Pipeline Hydraulic Profile 24

• 3.3 HYSYS Simulation Modelling 24

• 3.3.1 Hysys Compositional Modelling 25

• 3.4 PIPESIM Simulation Modelling 25

• 3.4.1 Pipesim Compositional Modelling 26

• 3.5 Pipe Flow Models and Flowsheets 27

• CHAPTER FOUR 30

• 4.0 Analysis of Results 30

• 4.1 Results achieved with the HYSYS simulation 30

• 4.1.1 HYSYS simulation results for design A 30

• 4.1.2 HYSYS simulation results for design B 33

• 4.1.3 Comparison of Designs A and B from HYSYS Outputs 35

• 4.2 Results achieved with the PIPESIM simulation 36

• 4.2.1 Suitability of pipe various pipe sizes 36

• 4.2.2 Outlet pressure analysis for design A & B 37

• 4.2.3 Fluid Mean Velocity for 10 inches sch 40 pipe size 38

• 4.2.4 Fluid Mean Velocity for 8 and 24 inches sch 40 pipe size 39

• 5.0 CONCLUSION AND RECOMMENDATION 41

• 5.1 Conclusion 41

• 5.2 Recommendation 43

• REFERENCES

EFFECTS OF FORMATION DAMAGE ON OIL WELL PRODUCTIVITY

ABSTRACT

Formation damage has been a constant headache to the oil producing industries as it is considered an impairment of the permeability of petroleum bearing formation with an expensive remediation procedure. Although, the prevention of formation damage is impracticable since every single operation embarked upon in petroleum production is a potential source of damage, it could be controlled. In this project, a well was studied and BHP survey was used from BHP analysis in addition to the information of the well history and reservoir data available. The well was observed to have been damaged with a skin of 115 and a damage ratio indicating the well should have been flowing about two times its present production rate. There are two major stimulation procedures which are the hydraulic fracturing and the matrix acidization in which the latter was used in the case of the damaged well. Well 57XX had a production rate which was initially 1550bbl/day at its peak before undergoing a decline, increased to 2100bbl/day and then continued to flow at an average of 2000bbl/day before a sharp decline and subsequent gradual declination of production rate showing the effect formation damage had on the well 57XX. This in conclusion proved that the matrix acidization technique used to stimulate the well was effective as it led to an increase in the well permeability and hence, increased the oil production rate.

CHAPTER ONE/INTRODUCTION

1.1. General Background
Formation damage is generally considered as the impairment of the unseen by the inevitable, causing an unknown reduction in the unquantifiable (Petrowiki, 2015). Also, it is a condition which occurs when barriers to flow develop in the near-wellbore region to give rise to a lower than expected production rate from or injection rate into a hydrocarbon bearing reservoir rock and it requires interdisciplinary knowledge and expertise (Amaefule et al, 1988). It can also be referred to as an impairment to reservoir (reduced production) permeability caused by wellbore fluids used during drilling, completion and work over operations (Petrowiki, 2015).
Oil well productivity on the other hand, is generally considered as the ability of a reservoir to produce hydrocarbons after the well has been drilled and made ready for production. The production stage of oil is the most important stage of a well’s life because it determines if the aim of drilling such well has been achieved or not, and this can be measured by the quantity of crude oil derived or quantity of crude oil which is producible. Formation damage is one of the major causes of decrease in oil production as a result of damage to the formation by reducing its porosity and permeability which also leads to flow restrictions. Flow restrictions into the wellbore create additional pressure drops known as ‘skin’ and reduce well productivity.
Formation damage is known to occur during any stage of a well’s life; from initial exploration, through appraisal, through production and through secondary or tertiary recovery and all these have their various roles which they play in the reduction of oil well productivity. Formation damage indicators include, among others, permeability impairment, skin damage and decrease of well performance. Formation damage according to Porter (1989) is considered not necessarily reversible and what gets into the porous media does not necessarily come out. It is, therefore, better to avoid the occurrence of formation damage rather than trying to restore it. Models for formation damages which have been proven to be verified can be used to avoid or minimize it (Faruk, 2011). Carefully planned laboratory and field tests can also help in providing scientific guidance as well as develop strategies for minimizing the damage. It will, therefore, cause considerable cost for remediation and deferred production. Accurately designed experimental and analytical techniques with the modelling and simulation approaches can be used to understand the evaluation, prevention, remediation and the control of formation damage that leads to low oil productivity.
Formation damage can occur as a result of fluid/rock incompatibility; particle migration and deposition may occur as a function of the chemistry of the clay minerals and the chemical and electrochemical nature of both the natural formation fluid and the drilling fluid. Changes in the pore fluid can also induce clay swelling which in turn reduces the pore spaces in the reservoir and this is considered a form of damage to the formation as it reduces the productivity of the formation.

The occurrence of the fluid/rock incompatibility is not as a result of only swelling of the clay and particle migration and deposition. Formation damage can also occur as a result of the fluid/fluid incompatibility. The incompatibility of the introduced fluid (drilling fluid) and the reservoir pore-fluid which creates emulsion blocks can only be controlled by stimulation techniques that include pre-flush or after flush techniques. Formation damage caused by various fluids introduced into the well is remediated by careful treatment design and quality control. The departure from radial flow in a homogenous and isotropic medium can also be a cause of formation damage. A positive skin may arise from a reduction of the area available to flow and/or a departure from purely radial flow (Harper and Buller, 1986).

Formation damage also has other causes such as the mechanical deformation around a borehole or perforation tunnel, reduction of fluid pressure during production, etc. Thorough understanding of the formation damage mechanism’s stringent measures for its control and prevention, and effective and efficient treatments are the keys for optimum production strategies for oil and gas fields.
The consequences of formation damage are the reduction of the oil and gas productivity of reservoirs and noneconomic operation. Hence, once formation damage has occurred, it is necessary that proper assessment, planning and treatment will require the cooperative efforts and knowledge of the geologists, reservoir engineer and production engineer both in the field and in the laboratory. This combined effort and approach will therefore help to develop effective solutions to the damage. A wide knowledge of the mechanism of formation damage is necessary in order for the engineers and geologists to develop effective, preventive and mitigating procedures.
With recent improvements in technology, laboratory, geology and engineering, it is easier to achieve accurate measurements which can provide the necessary insights into the mechanism, prevention and effective treatment of formation damage (Amaefule et al., 1988). Confidence in formation damage prediction using models cannot be achieved without undergoing field testing as they are necessary for the verification of the models. After the verification of the model, it can then be applied for accurate simulation of the reservoir formation damage and designing effective measures for formation damage (Faruk, 2011).

Formation has varying characteristics and a formation damage model can be used to incorporate these variations into a history matching process for the characterization of reservoir systems which can also be used for accurate prediction of future performance. Recent literature surveys have had various arguments and debate about if formation damage is considered more detrimental for the vertical wells or for the horizontal ones. However, the fact still remains that in both cases, the production loss due to formation damage is significant.