wellflo group project

PCB 3043: The Odom Field (Group Work)

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The Odom Field GROUP 1

Memo To: PCB 3043 students Dear all students / Group,

You should have 6 files including the following before commencing this project:

Odom Field, Question and Instruction - This file (READ this file CAREFULLY) GUIDE STEP BY STEP.doc - For details guide of WellFlo steps Odom-3 Completion Schematic.xls - Figure 1: Odom-3 Completion Diagram Odom-3 Well Schematic.xls - Figure 2: Odom-3 Well Schematic

The Project is divided into 3 parts:

PART A) Develop a Well Model for Odom-3

PART B) Sensitivity Analysis

PART C) Report

NB: Attach your Base Case Model file, .rvp and .dvp files when

submitting your reports on a CD for verification. GOOD LUCK.


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The Odom Field

The Odom field was discovered in June 1988 in the Gulf of Mexico in a water depth of 300 ft.

The field was developed using 5 wells and reached peak production in 1992. Since then, oil production has decreased rapidly due to increased water production.

Reservoir Properties:

The Odom sand was deposited in a turbidite environment. It is quite homogeneous with an average porosity and permeability of 22% and 200 mD, respectively. The reservoir sand, however, is anisotropic with a Kv/Kh ratio of 0.1. The top of the sand was encountered at 6400 ft TVDSS, and the oil-water contact is at 6500 ft TVDSS.

The reservoir is normally pressured with an initial reservoir pressure of 3300 psia and little or

no aquifer support. Reservoir pressure has declined with production to 2800 psia at present. Pressure maintenance was not considered when the field was being developed.

Table 1 lists the PVT data for the Odom fluids at current reservoir conditions.

Reservoir Temp. 150 F

Oil API Gravity 40 deg. API

Gas Sp. Gravity 0.80

GOR 500 SCF/STB

Pb 2115 psia

Bo 1.243 bbl/STB

Oil Visc. 0.71 cp

Bg 0.00458 ft^3/SCF

Gas Visc. 0.022 cp

Bw 1.023 bbl/STB

Water Visc. 0.67 cp

Water Salinity 200000 ppm

Z-Factor 0.73

Table 1: Odom PVT Data

Odom wells:

The Odom-3 field wells have an economical limit of 1500 STB Oil/Day/Well; i.e, producing at lower rate is not economically feasible.

Odom-3 was drilled in May 1995. It is taken to be the case study for this field as it has average parameters for Odom wells. Figure 1 is the completion diagram for Odom-3. Above the wellhead, the well was completed with the same 5 1/2" OD production tubing encased in a mud line (no insulation). The mud line connects the wellhead (on the sea-bed) to the Xmas tree on the platform.

Results of a recent pressure survey from Odom-3 are listed in Table 2.

Depth 650 1605 2590 3600 4590 5587 6490 ft TVD

Pressure 525 735 990 1292 1629 1920 2266 psia

Table 2: Odom-3 Pressure Survey


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Odom-3's well parameters, and results from both well testing and production logging are summarised in Table 3. Table 3 also contains a column on a new well Odom-1. Odom-3 and future location Odom-1 are located very close within its proximity.

Odom-3 Odom-1

Oil Prod. Rate 4770 New Well

STB/d

Water Cut 30 %

WH Flowing Temp. 65 F

Press. at X-tree 445 psia

Skin (Well Test) 2.92

New Well

PI (J) (Well Test) 12.35 STB/d/psi

Relative. Damaged

Zone Perm. 50%

Damage Zone

Thickness 12 Inches

Crushed Zone Skin 0.100

Drainage Radius 4000 ft

Table 3: Well Data

The Scenario:

The rate of oil production decline in the Odom field is alarming, and if no action is taken, Odom will become uneconomical by the end of the year. Due to improper management of previous Production Technology Team, operators of the field, PoloOil Inc., have fired the field's former team. PoloOil has hired your team to improve production from the Odom field.

Your Mission:

PoloOil has asked you to study the fields potential. The report shall outline A) the model you have used for your study B) the potential of the base case scenario C) your assessment of production enhancement proposals from the Odom engineers D) your recommendation for a project which will enhance production from Odom.

Include all relevant calculations and graphs in clearly labelled appendices. Save all your well

models. The paragraphs below are an elaboration on the sections of the report you will submit to management.

A) Develop a Well Model for Odom-3:

Using Odom-3 as your case study, complete the missing data in Figure 2-Odom. Next, using the company approved software (EPS's FloSystem), develop a model for the Odom field wells so that you can use it to fulfil tasks B: Sensitivity Analysis. Determine how detailed the model should be. Unnecessary detail means longer computing time and higher costs making you inefficient in managing resources. 1) Identify and list the major components contributing significant pressure drops along Odom-

3s completion string. Include only these components in your model. 2) Determine the best flow correlation model for Odom -3 and state the reasons for your choice.


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B) Base Case Analysis: As a good manager, the first thing you have to do is to evaluate the potential of what you have at hand at the moment. To achieve that, you must determine what effect the decline in reservoir pressure and the increase in water cut will have on Odom-3's production if nothing is done to improve its production. In other words, determine the reservoir pressure and the water cut at which

Odom -3 becomes uneconomical to produce under the current setup. N.B. PoloOil uses Vogel IPR

correlation for all well modelling.

Table B.1 is designed to assist you with that determination.

Table B.1: Odom-3 Oil Production Forecast

You discuss these figures with the fields engineers. Since artificial lift cannot be supported at present by the production facilities on the Odom-3 platform, you all agree that you have to start a water injection scheme to maintain the reservoir pressure at 2800 psia. Determine the production improvements from the Odom-3 field with this scheme in place in terms of the maximum water cut at which Odom-3 can produce economically. This will be considered as the base case scenario for this study. You realise that with water injection, you should expect higher water production from the well, and thus a shorter field life. To overcome this problem, operators often plug the "watered out" perforations. What are the advantages and disadvantages of such an operation?

Further Projects: You phone management and convince them to fund the pressure maintenance scheme. In addition, they agree to provide a budget for an extra project to improve Odom-3s production. In this section you must select the best project from your engineers suggestions below. Since production, and thus revenue, from Odom-3 is greatly affected by water production from the field, PoloOil defines the best production enhancement project for the Odom-3 field as the one that sustains economical production from Odom-3 at the highest water-cut. Therefore, this should be one of the criteria you use to select the project you recommend to management.

C. Optimum Production Tubing Size:

Tubing Selection One morning, you had a coffee with your senior engineer, Mr. T, Head of Production Engineer of your company. You had a chat regarding the Odom-3well performance. The production seems to decline as reservoir pressure declining. He suggested for you to look on options of changing the tubing sizes on the lower portion of your production string. Knowing that you have an option to choose the optimum production tubing size to be installed, examine the tubing performance for depleting reservoir pressures. Use the following information to run your sensitivity analysis.

Pres

WC

2800 2700 2600 2500

30% 4770

35%

40%

45%

Psia


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Tubing OD

(in)

Tubing ID

(in)

Weight

(lb/ft)

3.5 3.068 7.7

4.0 3.548 9.5

4.5 4.090 11

5.0 4.494 13

5.5 4.767 18

Table C1: Available tubing sizes for Odom-3

Your optimum tubing size will be based on the maximum production rate at 2800psi reservoir pressure.

Table C2: Oil production forecast as functions of tubing sizes and reservoir pressures

b) After installing optimum tubing size of __________inch dia., Odom-3 is having maximum water cut at which the well can produce economically of ________%. (See Figure ______)

c)

Scenario Maximum economic

water cut

Oil production rate

at 30% water cut

Optimum tubing size

d) State the two main factors in choosing the optimum production tubing size. Explain your answer

D. Another Production Technology Suggestion: Artificial Lift After lunch, Odom-3 Senior Production Technologist steps into your office. He says that while he was having lunch, he remembered that PoloOil has been quite successful using Electric Submersible Pumps (ESPs) in the nearby field. Additionally, he says that gas lift may be an option as the well has a high PI and the PoloOil has sufficient gas supply from another nearby field. He says that he is aware of the drilling department suggesting a slanted well, but installing artificial lift will be quicker and cheaper than side tracking the well. He suggests investigating the installation of an artificial lift

scheme with a target liquid rate of 9000 STB/d.

D1: Gas Lift Design

a) Given the current conditions carry out a gas lift design for Odom-3 with the details and engineering assumptions below, Max casing head pressure: 1200 psi Gas available for injection: 20MM scf/d Injected gas gravity: 0.6 Maximum setting depth: 3900 ft

Pres

OD

2800 2600 2400

3.5

4.0

4.5

5.0

5.5

Psia


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Valve differential pressure: 100 psia Minimum spacing: 450 ft Kill brine density: 0.465 psi / ft Minimum safety margin (Casing closing pressure margin): 50 psi

Assumptions: 1) Production tubing is unaltered. 2) Unload the tubing full of static fluid against the well head pressure (i.e. static fluid to 0ft MD). 3) No transfer margin is required. Show the gas lift design plot in your report, determine the required gas injection rate for the design production rate and explain briefly the different roles of valves in your design. Should the unloading valves be open or closed when assessing gas lift capabilities? b) Determine the technical optimum injection rate as the reservoir pressure declines and summarise the results in Table D1 (Answer Form).

Pres 2800 2600 2400 2200 2000

Technical

optimum

injection rate

Table D1: Technical optimum gas injection rate for Odom-3.

Explain the reasons for your choice in your report. Why are technical optimum injection rates not

applicable in practice? What other possible factors have you considered in completing the Table D1? Explain to management the reason why greater gas injection rates do not result in greater production as the reservoir declines.

c) Redesign the Gas Lift scheme using the optimum gas injection rate for 2800 psia. Determine the

benefit from installing Gas Lift in Odom-3 in terms of the maximum water-cut at which the optimised injection rate will sustain economic production.

E. Another Production Technology Suggestion: Acidizing & Fracturing Techniques Another option is to look into the possibility of restoring the permeability to the original state. The Production Engineer suggested to you that there are chemicals available to inject into the formation so as to remove the skin around the wellbore and advised that you have a look into this viable option. Otherwise, there is also the possibility of increasing the shot penetration (perforation depth) beyond the damage zone thickness as a form of fracturing.

Table E1: Oil Production forecast for acidizing technique

Pres

Perm.

2800 2700 2600 2500

100md

200md

Psia


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Table E2: Oil Production forecast for fracturing technique Complete the oil production forecast in Table E1 and E2 and compare results before and after acidizing and fracturing techniques. Present the inflow and outflow graphs in each case. (Use this result to compare the benefits from this project to the other proposed projects, and as a basis for your recommendations).

F) Report:

Present all your works in report format with relevant plots for evidence. The format should follow a common report format, i.e. Your report should have (not limited to): Introduction, Methodology, Results and discussion, Conclusion, Recommendation, etc.

G. Recommendations to Management: 1) Assess the production enhancement projects proposed by the Odom-3 field engineers in section D above and compare them to one another and to the base case scenario. Put in mind that PoloOil has set the ranking criteria for these projects to be the maximum water-cut at which Odom-3 can sustain

economic production (i.e. > 1500 STB oil/d). 2) Based on this assessment, recommend to management a plan of action: either recommending to maintain the base case scenario, or to execute one of the proposed projects. 3) By setting the maximum water cut as the ranking criteria for the above projects, a number of risks have been overlooked by this assessment, all of which add to the uncertainty of its results and your recommendation. As the Odom-3 field team leader, it is your duty to report and account for these risks to management. Identify three major risks that have not been included in this assessment. Briefly explain how each one could add to the uncertainty of this assessment, and prescribe the necessary steps that need to be taken to account for their effects.

Pres

Perf.

2800 2700 2600 2500

9-in

10-in

11-in

12-in

Psia


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Appendix

Further Instructions on The Odom Field Exercise Please read and follow the following instructions when carrying out the Odom Field exercise. Read all the handouts carefully as this is quite challenging exercise. Fill-out the missing

data in Figure 2. With the aid of this appendix, attempt to carry-out this exercise. In most sections of this exercise you have more information than you need. This is to help

you verify that the model you are using is correct.

WellFlo data input:

NOTE 1: The Xmas tree node in WellFlo represents in reality the wellhead on the sea-bed and not the Xmas tree on the production platform.

Before you enter any other data, make sure that the data in the Xmas tree node is in accordance with Figure 2.

Next, enter well deviation and equipment data. This well is a vertical well

NOTE: Do not forget that you need to connect the wellhead on the sea-bed to the production platform.

In Reservoir Control, choose the layer parameter entry model.

Enter the reservoir Fluid Parameters. Decide which, if any, of the correlation model fluid parameters should be matched to the actual fluid parameters. Check that the reservoir fluid model calculates fluid parameters' values that conform (more or less) with the actual reservoir fluid parameters.

Enter Layer Parameter Data. In Skin Analysis, use the calculated skin option. Make sure that the calculated skin matches the one obtained from well-test.

Nodal Analysis:

The top node should be the Xmas tree on the production platform. In this model it is represented by the Outlet Node.

Use the Calculated Temperature Model with sea-water temperature of 50F and atmosphere temperature of 65F.

Make sure that the model iterates to exact operating point and does not check for flow stability (in Analysis/ Operating point)

NOTE:

For Detail Procedure on the Well modelling example (complete with figures), please refer

to Guide Step by Step file.

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