A Study Of Production Optimization Of An Oil Copy

M.Eng. Project DefenceBy: Aadrish Mir

Supervisor: Dr K.C. WattsReader: Dr D. Garagash

A STUDY OF PRODUCTION OPTIMIZATION OF AN OIL WELL USING PROSPER

The objective of the project is first given. Well deliverability and phase behavior concepts

are defined. Nodal Analysis & its applications are discussed. An introduction to PROSPER software is

mentioned. A case study emphasizing on the use of

production optimization of an oil well with PROSPER software is presented.

Presentation Outline

The objective of the project is to optimize well performance in order to maximize the production rate.

Oil reserves are depleting every day and oil prices are peaking, thus the role of production optimization cannot be neglected.

Objective

Well deliverability is determined by a well’s inflow performance.

The Inflow Performance Relationship (IPR) is defined as the functional relationship between the production rate and the bottom hole flowing pressure.

Productivity Index (PI or J) expresses the ability of a reservoir to deliver fluids to the wellbore.

Productivity Ratio (PR) is the ratio of actual productivity index to the ideal productivity index where skin, s=0.

Reservoir Deliverability System

The reservoir fluid can be classified into basically three types i.e., single phase, two phases, or a combination.

Such information is used to determine the type of IPR equation to be used.

Phase Behaviour

Fig 2.3 A typical p-T diagram for ordinary black oil (Ahmad, 2001).

A systems analysis approach, often called NODAL Analysis, has been applied to “analyze the performance of systems composed of interacting components.”

Its application to well producing systems was first proposed by Gilbert (1954).

Nodal Analysis

A partial list of possible applications of nodal analysis include: Selection of tubing size. Selection of flow line size. Analysis of an existing flow system for

abnormal flow restrictions. Artificial lift design. Prediction of the effect of depletion on

production capacity.

Applications

1) Determine which components in the system can be changed.

2) Select one component to be optimized.3) Select the node location that will best emphasize the

effect of the change in the selected component. 4) Develop expressions for the inflow and outflow.5) Obtain required data to calculate pressure drop versus

rate for all the components. 6) Determine the effect of changing the characteristics of

the selected component by plotting inflow versus outflow and reading the intersections.

7) Repeat the procedure for each component that is to be optimized.

Procedure

PROSPER is a well performance, design and optimization software.

PROSPER is designed to allow the building of reliable and consistent well models, with the ability to address each aspect of well bore modeling viz:

Pressure Volume Temperature (PVT) fluid characterization

Vertical Lift Performance (VLP) correlations for calculation of flow-line, tubing pressure loss and

Inflow Performance Relationship (IPR) for the reservoir inflow.

PROSPER

SYSTEMS ANALYSIS USING PROSPER

The well used in this case study will be designated as X-3

The field was developed using 5 wells and reached peak production in 1996. Since then, oil production has decreased rapidly due to an increase in water content

An economic limit of 1500 STB Oil/d/well was premised; i.e. producing at rates lower than that is not economical.

Case Study of Optimization of an Oil Well Using PROSPER

Water depth 300 (feet)

Average porosity 22 (%)

Permeability 200 (mD)

Kv/Kh 0.1

Top of sand 6400 (ft) TVDSS

Oil-water contact 6500 (ft) TVDSS

Initial reservoir pressure 3300 (psia)

Present reservoir pressure 2800 (psia)

Table 1 Reservoir Data

Table-5.1 PVT Data

Reservoir Temperature 150 (°F)

Oil API Gravity 40 (°API)

Gas Relative Density 0.80

GOR 550 (scf/STB)

Pb 2030 (psia)

Bo 1.27

Oil Viscosity 0.66 (cp)

Bg 0.0046

Gas Viscosity 0.022 (cp)

Bw 1.023

Gas Z Factor 0.73

Water Salinity 200000 (ppm)

Water Viscosity 0.67 (cp)

Depth,

(ft)

TVD

650 1605 2590 3600 4590 5587 6490

Pressu

re,

(psia)

525 735 990 1292 1629 1920 2266

Table-5.2 Pressure Survey

Table-5.3 Well Data Table-5 .4Well Equipment Data

Node NoComponent

Name

Measured

Depth (ft)

1Outlet node/

Christmas tree0

2 Riser 350

3 Wellhead 350

4 5.5” Tubing 850

5 S.C.S.S.S.V 850

6 5.5” Tubing 4000

7 5” Tubing 5600

8 7” Liner 6530.5

Oil Production rate,

(STB/d)4730

Water Cut, (%) 30

WH Flowing Temperature,

(°F)65

Pressure at Christmas tree,

(psia)445

Skin (Well Test) 2.92

PI or J (Well Test),

(STB/d/psi)12.36

Damaged Zone Relative

Permeability, (%)50

Damage Zone Thickness,

(In)12

Crushed Zone Skin 0.100

Damage radius, (ft) 4000

Develop a well performance model using PROSPER

Simulate base case forecast under various operating conditions

Evaluate various development options to optimize oil production

Results

Case Study Objectives

Developing a well performance model using PROSPER

Table-5.5 Data entry in PROSPERFluid Oil & Water

PVT method Black Oil

Separator Single-Stage Separator

Flow Type Tubing Flow

Emulsions No

Well type Producer

Lift method None

Predicting Pressure only

Completion Cased hole

Gravel Pack No

Fig-5.2 IPR plot

Fig-5.3 Downhole equipment

Matching the Model

Table-5.7 Match dataOil Rate (STB/d)

Measured Calculated % Difference

4730 4704.4 -0.54061

Fig-5.7 VLP-IPR matching

Flow diagram for data entry and results in PROSPER

Since the PVT, VLP and IPR were matched to measured data, it was possible to move on and use the model to perform a system analysis

Simulate Base Case Forecast under Various Operating Conditions

Table-5.8 Reservoir pressure & water cut rangesTable-5.9 Oil rates at given parameter ranges

Table-5.10 Economic base case conditionsScenario Maximum Economic

Water Cut

Production Rate @ 30 (%)

Water Cut

Base Case 45 (%) 4703.(STB/day)

Reservoir

Pressure (psig)

Water Cut (%)

30 35 40 45

Oil Rate (STB/d)

2800 4703 3818 2993 2232

2700 3922 3073 2288 1564

2600 3120 2307 1436 0

2500 2292 0 0 0

Parameter Range

Water cut 30,35,40,45 (%)

Reservoir Pressure 2500,2600,2700,2800 (psig)

A sensitivity run on the current reservoir conditions for decreasing well head pressure (WHP) was performed.

WHP can be adjusted using choke in an oil well.

Reduction in WHP causes the drawdown to increase which in turn increases the oil production.

Evaluate Various Development Options to Optimize Oil Production

Changing WHPTable-5.11 Oil rate at various WHP & WC

Table5.12 Oil rate at economic water cut

Scenario Maximum Economic Water

Cut

Production Rate @ 45 (%)

Water Cut

Lowering christmas tree

pressure

70 (%) 6153 (STB/d)

WHP (psig) WC @ 45

(%)

WC @ 50

(%)

WC @ 60

(%)

WC @ 70

(%)

WC @ 80

(%)

Oil Rate (STB/d)

445 0 0 0 0 0

400 1538 0 0 0 0

300 3125 2294 0 0 0

200 4788 3873 2140 465 0

100 6153 5238 3463 1833 364

For further production of the remaining oil in the reservoir, adjusting the tubing size was required and sensitivity analysis of various tubing sizes (internal diameter) was performed.

The effect of increasing the tubing size is to give a higher node pressure for a given flow rate because the pressure drop in the tubing is decreased.

If the tubing is too small even though the reservoir may be capable of producing a large amount of fluid too much pressure drop occurs in the tubing.

Changing Tubing Size

Changing Tubing Size, continuedTable-5.13 Oil rate at various tubing internal diameter sizes

Tubing Size ID (in) Oil Rate (STB/d)

2.441 257

2.992 315

4.09 346

4.892 0

A gas lift for X-3 was undertaken based on current conditions and engineering assumptions.

The purpose of injecting gas into the tubing is to decrease the density of the flowing gas-liquid mixture and therefore decrease the required flowing bottom hole pressure.

As the gas rate is increased the fluid velocity and therefore the friction losses also increase.

Gas Lifting (Artificial-Lift Method)

Gas Lifting, continued

Table-5.15 Oil rate with various gas injection rates

Table-5.16 Economic oil rate with optimized gas liftScenario Maximum Economic Water

Cut

Production Rate @ 45 (%)

Water Cut

Optimised gas lift 80 (%) 6900 (STB/d)

Gas Inj. (MM scf/d)WC @ 45

(%)

WC @ 50

(%)

WC @ 60

(%)

WC @ 80

(%)

WC @ 90

(%)

Oil Rate @ Different Water Cut (STB/d)

2 6908 6091 4534 1870 824

3 7039 6233 4697 2003 900

4 7111 6313 4782 2075 938

Lowering the Christmas tree pressure to 100 psi is recommended because the well’s life can be extended to 70% water cut

The next possible option is to change the tubing size. However changing the tubing size is not recommended, since it does not produce a fruitful increment in oil production rate.

The gas lift method is more economically beneficial as it produces up to a maximum economic water cut of 80% with gas injection rate of 2-4 MM scf/d producing oil rates of 1800-2000 STB/d.

Case Study Results

Thank You