2011CHG0076

STUDENTS INDUSTRIAL WORK EXPERIENCE

SCHEME (SIWES)

WITH

STERLING OIL EXPLORATION AND ENERGY

PRODUCTION CO. LTD.

Supervisor: Prepared by:

Mr. Lincoln Bassey Eloka V. Adaeze

OUTLINE

ABSTRACT

1. DRILLING AND COMPLETIONS

1.1 INTRODUCTION

1.2 DRILLING

1.2.1 Typical Casing Profile

1.2.2 Getting Ready to Spud

1.2.3 Spudding

1.2.4 Running the Surface Casing

1.2.5 Running the Intermediate Casing

1.2.6 Running the Production Casing

1.2.7 Running the Production Liner

1.3 COMPLETIONS

1.3.1 Single String with Single Packer

1.3.2 Dual String with Multiple Packers

1.3.3 Single String with Multiple Packers- Selective Zone

1.3.4 Christmas (Xmas) Tree

2. PETROLEUM GEOLOGY

2.1 INTRODUCTION

2.2 FORMATIONS IN THE NIGER DELTA

Students Industrial Work Experience Scheme (SIWES) with SEEPCO 06/2011 to 10/2011: Adaeze Eloka 2

3. MDT PRESSURE GRADIENT SURVEY

3.1 DETERMINATION OF FLUID TYPE AND

CONTACTS FROM PRESSURE-DEPTH PLOTS

3.1.1 Introduction

3.1.2 Objectives

3.1.3 Evaluation

3.1.3.1 OKW-A Reservoir

3.1.3.2 OKW-B Reservoir

3.1.3.3 OKW-C Reservoir

3.1.3.4 E7000 Reservoir



3.1.4 Conclusion

4. PRESSURE VOLUME TEMPERATURE

4.1 PVT ANALYSIS OF FLUID SAMPLES GOTTEN

FROM AGU FIELD

4.1.1 Introduction

4.1.2 Objectives

4.1.3 Results

4.1.4 Conclusion

5. APPENDIX


ABSTRACT

Sterling Oil Exploration and Energy Production Co. Ltd (SEEPCO) is an oil company

involved in the exploration and production of hydrocarbons in Nigeria. Presently, they

operate on two blocks; Okwuibome field located in OML 143, Kwale, Delta State and

Agu field located in OPL 277, Owerri, Imo State.

During the training period, I was assigned to two different departments; operations

department and subsurface department. This report is divided into four sections; drilling

and completions, petroleum geology, modular formation dynamics tester (MDT) pressure

gradient survey and pressure volume temperature (PVT) analysis, based on my

assignments in Sterling.

The drilling and completions section contains information about Sterling’s wells, the

drilling process applied and the typical casing profile Sterling uses. Also, the type of

completions that were used to complete Sterling’s wells along with sketches of the

completion strings. The petroleum geology section contains information on the geology of

the Niger Delta and the formations in the Niger Delta.

The modular formation dynamics tester (MDT) pressure gradient survey involved the use

of pressure data to plot graphs which were used to locate the oil, water and/or gas zones

along with the location of the oil-water contact and/or gas-oil contacts if any.

The pressure volume temperature (PVT) analysis used PVT data gotten from the

laboratory to determine the bubble point pressure of the reservoir, formation volume

factor, solution gas oil ratio, viscosity and composition of the reservoir fluid.


1. DRILLING AND COMPLETION


1.1 INTRODUCTION

Sterling uses rotary rigs to drill her wells. Two rotary rigs were assigned; Durga-1 and

Durga-2. These rigs were operated by BOGEL (the drilling service company). Durga-1

was used to drill four completions in the II pack sands. Two of the completions were

vertical wells while the other two were horizontal wells and they were all shallow sands.

Durga-2 drilled two vertical and one dually completed well, making four completions in

IV pack sands. Durga-2 which is used for drilling high pressure and high temperature

zones was used to drill these wells because the IV pack sands are deep with high pressure

and temperature.

Rotary drilling consists of two types of rotating systems that can be used; rotary table

system and top drive system. The top drive system was used to drill all Sterling’s wells

except OKW-9 where the rotary table system was used.

1.2 DRILLING

The companies involved in the drilling operations include;

Drilling contractors

Mud contractors

Mud loggers

Cement contractors

Logging company

The drilling contractors consist of the tool pusher, tour pusher, driller, assistant driller,

floor men, derrick man, and derrick pusher. The mud contractors are in charge of mixing

mud. The mud logger monitors drilling parameters like depth, rate of penetration,

cuttings analyses and so on. The cement contractors are in charge of cementing the casing

to the borehole wall. The logging company performs all well logging operations while

drilling.

At the planning stages of drilling Sterling’s wells, the drilling engineer, with input from

the Geo-scientist, petrophysicists, reservoir engineers and production engineers decided

on the strategy to adopt for the appraisal drilling of proposed wells.


1.2.1 Typical Casing profile

The hole drilled for each casing must be large enough to easily fit the casing inside it,

allowing room for cement between the outside of the casing and the hole. Also, the inside

diameter of the first casing string must be large enough to fit the second bit that will be

used to continue drilling.

Usually, a well contains multiple intervals of casing successively placed within the

previous casing run. The following casing profiles were used for Sterling’s wells design;

Conductor casing

Surface casing

Intermediate casing

Production casing

Production liner

During drilling of the well(s) the logging tool is run in hole to measure formation

parameters, along with the MDT tool. The MDT takes pressure measurements and

pressurized fluid samples. These fluid samples are taken to the laboratory for Pressure-

Volume-Temperature analysis. The DST tool on the other hand is run in a cased hole

section along with the perforating gun. When the gun perforates the casing, the DST tool

measures the formation’s flow pressure.

1.2.2 Getting Ready to Spud

Drilling land wells begin with digging a cellar which can be from 3-15feet. The primary

purpose of the cellar is to align the Christmas tree at relative ground level. This allows for

easier access to the valves, choke, and other equipment. The first string of pipe is called

the conductor pipe or drive pipe which is usually 30” for Sterling’s wells.

Below are the steps taken preparatory to drilling and completion of wells;

1.2.3 Spudding

A large diameter hole is drilled to a specified depth generally relatively shallow,

such as 1 ft or 200 ft.

The pipe is driven into the ground to the point of refusal.


1.2.4 Running the Surface Casing

After drilling 26” surface hole, the 20” surface casing is run to a specified depth

to isolate any fresh water, salt water, and oil or gas zones within that depth range

of the formation. Cement is circulated to surface of the 20” surface casing.

1.2.5 Running the Intermediate Casing

After the 17 ½” hole has been drilled, 13-3/8” intermediate casing casing is run in

the hole and cemented to a predetermined depth to ensure a good cement bond is

obtained between the surface casing and the intermediate casing.

1.2.6 Running the Production Casing

The 12 ¼” hole is drilled and 9-5/8”production casing is run and cemented in

place.

1.2.7 Running the Production Liner

The production liner is run to the total depth of the well. When the 6” hole is

drilled, the 4 ½” production liner is installed and cemented in place.

See figure below

30” conductor casing

cement

Casing shoe

26” hole

20” surface casing

17 ½” hole

13 3/8” intermediate casing

12 ¼” hole

9 5/8” production casing

6” hole

4 ½” production liner

Figure: typical casing profile


1.3 COMPLETIONS

Well completion is composed of tubular, tools and equipments placed in a wellbore to convey, pump or control the production or injection of fluids. Wells can be completed as;

Open hole or cased hole Single string completions, dual string completions, single selective completions

etc Naturally flowing or artificially flowing wells

Openhole completions are feasible only in reservoirs with sufficient formation strength to prevent caving or sloughing; such as carbonate reservoirs. Cased hole completions are feasible in reservoirs without sufficient formation strength such as sandstone reservoirs which are unconsolidated. Cased hole involve using a set of casing set through the producing reservoir and cemented in place. Fluid flow is established by perforating the casing and cement sheath, thereby opening and connecting the reservoir to the wellbore.Sterling does cased hole completions because formation structure in the Niger delta is sand stone. The tubing configurations used includes the following;

Single string with single packer Dual string with multiple packers Single string with multiple packers- Selective Zone


1.3.1 Single String with Single Packer

This is a single string flow conduit. There is both tubing and annulus flow. The packer is

run in hole, installed in place and pressure tested, and then the tubing string is run in-

between the packer. The packer holds the tubing string in place and establishes hydraulic

separation between the tubing string and the casing or liner.

Flow Coupling

Selective Landing Nipple

Tubing Seal Divider

Sliding Sleeve

Packer

No-Go Nipple

Figure: single string with single packer


1.3.2 Dual String with Multiple Packers

In the dual string with multiple packers, several zones can be lifted simultaneously. In the figure below, the fluids in the upper zone is produced through the short string which is 2-7/8” OD while the fluids in the lower zone is produced through the long string which is 3-½” OD. The dual string is usually placed in the 9-5/8” production casing.

Sliding Sleeve

No-Go Nipple

Packer

Flow Coupling


Blast Joint

Polished Nipple

Tubing Seal Divider

Packer

No-Go Nipple

Figure: dual string with multiple packers


1.3.3 Single String with Multiple Packers- Selective Zone

In the single string with multiple packers, the zones can be produced one at a time or they can be co-mingled depending on government regulations or the quality of the fluids. If the zones are to be produced one at a time, the producing sections can be opened or closed by shifting the sliding sleeve, using wireline services.

Sliding Sleeve

Packer

Sliding Sleeve

Flow Coupling


Blast Joint


Packer

Flow Coupling

Blast Joint


Packer

No-Go Nipple

Figure: single selective string with multiple packers


1.3.4 Christmas (Xmas) TreeAt the top of the well completions is the Christmas tree which is an assembly of valves, spools, pressure gauges and choke. The tree prevents the release of oil and gas from the well into the environment, directs flow of oil and gas from the well.

Figure: the production Christmas tree

The swab valve provides vertical access to the wellbore, see figure above. The surface

choke is used to control fluid flow rate or downstream system pressure. Wing valves are

incorporated into the wings of a Christmas tree to provide access to the production tubing

for production and well control purposes. The two wings featured in the Christmas tree

include a production wing connected to the surface production facilities, and a kill wing

that may be used for well control or treatment purposes.

A correctly functioning master valve is so important that two master valves are fitted to

the Christmas tree. The upper master valve is used on a routine basis, with the lower

master valve providing backup in the event that the normal service valve is leaking and

needs replacement.


The production string is the primary conduit through which reservoir fluids are produced

to surface. The production string is typically assembled with tubing and completion

components in a way that suits the wellbore conditions and the production method. An

important function of the production string is to protect the primary wellbore tubulars,

including the casing and liner, from corrosion and erosion by the reservoir fluid.


2. PETROLEUM GEOLOGY


2.1 INTRODUCTION

Hydrocarbon originates from micro-organisms in the seas, river, lakes and land. When

these organisms die, they deposit at the bottom of the sea where they form organic matter

as sediments.

As more of these micro-organisms die, they are deposited on the previous sediments

during which pressure and temperature increases. This increase creates a reducing

environment during which oxygen is stripped from the sediments and they become

compacted thereby forming sedimentary rocks.

Hydrocarbons are mostly found in anticlinal structures; as a result, they are sought out by

geologists who explore for oil and gas. Since oil and gas are less dense than water, they

tend to migrate upward through permeable rock. When rock is folded into an anticline

and capped by an overlying impermeable rock, then oil and gas will migrate up the slope

of the fold to the crest and accumulate there.

Some hydrocarbon traps are created by faulting. Some of the faults in the Niger Delta are;

Rollover anticline

Listric fault: this is a spoon shaped fault.


Collapsed crest: this is where compressional forces push a block of rock upward

Growth fault: this is a situation where the hanging wall is thicker than the footwall

Counter regional fault: this is a C-shaped fault

Antithetic fault: this is a fault where the hanging wall dips to the north

Synthetic fault: this is a situation where the hanging wall dips to the south

2.2 FORMATIONS IN THE NIGER DELTA

There are three formations in the Niger Delta;

Benin formation

Agbada formation

Akata formation

The Benin formation contains unconsolidated fine beach sand basically. The gamma ray

reading in this formation is low because sand contains little or no radioactive particles.

This sand also contains fresh water which has high resistivity and can be mistaken for

hydrocarbon, but hydrocarbon can not be found in the benin formation because it is

separated from Agbada formation by a very thick shale called the upper agbada shale.

Agbada formation is where the hydrocarbon is trapped. In this formation, there is sand

and shale intercalation and the water in Agbada formation is saline resulting in low

resistivity. Therefore if high resistivity is encountered in Agbada, it is usually perceived

to be hydrocarbon.


The Akata formation is where the hydrocarbon is formed before it migrates up to the

Agbada formation. This formation consists mainly of marine shales and the pressure and

temperature here is very high because of its position.


3. MDT PRESSURE GRADIENT SURVEY


3.1 DETERMINATION OF FLUID TYPE AND CONTACTS FROM PRESSURE-DEPTH PLOTS

3.1.1 Introduction

Okwuibome field is located in OML 143 and is situated in the northern depositional belt

of the Niger Delta.

Sterling has drilled some wells in the field. Okw-A well was completed in IID sands

while Okw-C and Okw-B wells were completed in IVA-1 sand. The three wells were

completed up dip of the reservoir.

Hydrocarbon from the IID reservoir has 19°API gravity with Gas Oil Ratio (GOR) of

about 6scf/bbl. The reservoir quality of the IID sands is good with a porosity ranging

from 26 to 28%, and the oil is relatively viscous.

IVA-1 reservoir has 49° API gravity with Gas Oil Ratio (GOR) of about 2000scf/bbl. The

reservoir quality for the IVA-1 sand is also good with the porosity ranging from 23 to

25% and an effective permeability of 148 Darcy, the oil here is not as viscous as the oil in

the IID sand. The initial pressures for OKW B and C are 4774.63psia and 5158psia

respectively.

Agu main field on the other hand is in Block OPL-277 which is located in Imo state. Agu

2 and Agu 3 appraisal wells were drilled which encountered several sands including

sands E7000, E7500 and E8000. The reservoir’s porosity is within the range of 25% to

32%, and permeability in the range of 5 to 6 Darcy. The oil gravity is between 22 and 26

degrees API gravity, with a very low GOR of 200 to 260scf/stb, although a high GOR

was encountered in E8000.


Modular Formation Dynamics Tester (MDT) survey and sampling were carried out on

three wells; OKW-A, OKW-B and OKW-C in Okwuibome field and on three wells;

E7000, E7500, E8000 in Agu field. The purpose of carrying out this survey was to

identify the fluids in the reservoir and their contacts, as well as obtain fluid samples for

Pressure Volume Temperature (PVT) analysis.

Formation testers were introduced about 55 years ago for the sole purpose of sampling

fluids in the well. The formation tester was first introduced by Schlumberger, later oil

servicing companies such as Baker Hughes, Halliburton etc. produced their own versions.

When this tool was first introduced in 1955, it was specifically supposed to collect

reservoir fluid samples but could only collect one sample per trip in the well. It was later

replaced by the formation interval tester and then the repeat formation tester in 1975,

(See Figure 1). Presently, Schlumberger’s MDT tool offers significant improvements in

pressure measurement with the introduction of the combinable quartz gauge (CQG) and it

also offers improved sampling capabilities.

Figure 1: The transition of formation testers over the years

The Schlumberger MDT tool was used for pressure survey and fluid sampling in OKW-

A, B, C and E7000, E7500 and E8000 wells respectively. The results from this survey

were compared with logs that were measured while drilling. Some of the logs used were

the gamma ray log, resistivity log, etc. The gamma ray curve provides lithology


information such as sandstones and shales. Low gamma ray reading indicates sandstone

while high gamma ray reading depicts shales. Hydrocarbons from petrophysical

interpretation of the composite logs (gamma ray curve, resistivity curve, neutron-density

curve, etc) always exist in the sands/sandstone.

Resistivity curve gives an idea of fluid types contained in the sandstone. Since water is a

conductor of electricity and hydrocarbons are insulators, the resistivity reading in a water

zone is usually lower than the resistivity reading in a hydrocarbon zone. So, wherever

there is a drop in resistivity in a sandstone region, it means that that point is a

hydrocarbon-water contact/oil-water contact.

The neutron-density curve on the other hand indicates the exact type of hydrocarbon in

the sandstone by measuring their densities. The densities of the hydrocarbons have

opposite effects on these two measurements. As a result, the two measurements are

plotted on a graph in such a way that the two curves overlap in the water-bearing zone. In

the gas zone, there is a large separation with neutron on the right and density on the left.

This separation is called the gas separation. In the oil zone, the two curves nearly overlap

each other while in shales, the separation that occurs is the inverse of what happens in the

gas zone. Here the neutron curve shifts to the left while the density curve shifts to the

right.

3.1.2 Objectives

Identify fluids from their pressure gradients.

Determine the position of the gas/oil and oil/water contacts from pressure-depth

plots.

Evaluate samples obtained for PVT analysis.

3.1.3 Evaluation

3.1.3.1 OKW-A Reservoir: the pressure plot of well OKW-A showed OWC at 1691m

TVD SS and the pressure gradients calculated were 0.404psi/ft for oil and 0.438psi/ft for

water. The pressure gradients are close because the density of the oil is almost up to that

of the water. This trend is seen on the pressure plot, as the plot is almost linear. From the


pressure gradient calculated, the oil is heavy oil. On the gamma ray curve, from 1679m to

1772m shows sandstone because of the low gamma ray reading in that section. The

resistivity curve at that section indicates a resistivity drop at 1691.2m and since

hydrocarbon has a higher resistivity than water, it means that the OWC is at 1691.2m (see

figure 2). The neutron-density curve at that section shows that the density of the oil is

close to that of water because the overlapping of the curves is almost the same.

Figure 2: MDT for OKW-A Reservoir

3.1.3.2 OKW-B Reservoir: the pressure plots showed OWC at 3130m TVD SS in

OKW-B and the pressure gradients calculated were 0.149psi/ft for gas, 0.215psi/ft for oil

and 0.457psi/ft for water. From the pressure gradients calculated, the gas is gas

condensate which is a low density mixture of hydrocarbon liquids e.g. pentane, hexane,

heptanes, etc, while the oil is volatile oil. On the gamma ray curve, from 3118m to

3154m is sandstone because of the high gamma ray reading in that section. On the

resistivity curve, from that section, there is a sharp resistivity drop at 3134.5m. This can

only mean that from that point of the resistivity drop downwards is a water zone.

Therefore, the OWC is at 3134.5m. (see Figure 3). The neutron-density curve for OKW-

B is not accurate because of the scaling that was used.


Figure 3: MDT for OKW-B Reservoir

3.1.3.3 OKW-C Reservoir: the pressure plots showed the OWC at 3159m in OKW-C

and the pressure gradients calculated were at 0.234psi/ft for oil and 0.42psi/ft for water.

The pressure gradient for oil shows that it is volatile oil which is oil that evaporates

rapidly and doesn’t leave stains. It can also be called clean oil or good quality oil. On the

gamma ray curve, from 3152m to 3196m is sandstone because of the high gamma ray

reading in that section. On the resistivity curve, from that section, there is a sharp

resistivity drop at 3166.5m. This means that from the point of the resistivity drop

downwards is water zone. Therefore, the OWC is at 3166.5m. (see Figure 4). The

neutron-density curve for OKW-C is not accurate because of the scaling that was used.


Figure 4: MDT for OKW-C reservoir

3.1.3.4 E7000 Reservoir: Based on the MDT pressure measurement, the gas and water

gradient were determined as 0.089 and 0.45 psi/ft. The gradient calculated for the gas

classifies it as dry gas. In the oil column, a pressure gradient of 0.39 psi/ft was

determined from fluid sample. This gradient value indicates that the oil is heavy oil, see

figure 5. The MDT data was unable to infer contacts due to poor pressure data obtained

in the oil column.

Figure 5: MDT for E7500 reservoir


3.1.3.5 E7500 Reservoir: Three fluids were present in this sand (gas, oil and water). The

gradients were calculated from the pressure plots to be 0.05, 0.36, and 0.43 psi/ft, for gas,

oil and water respectively. These gradients show that the gas is dry gas and the oil is

black oil. The GOC was at 1768 m-ss and OWC was at 1774 m-ss.




Two fluids were present in this sand (oil and water). Based on the slopes generated from

the pressure plots, the fluid gradients were calculated as 0.36, and 0.45 psi/ft, for oil and

water respectively. The gradient for the oil defined it as heavy oil. The fluid contact

within the reservoir was defined as, OWC at 1815 m-ss.


3.1.4 Conclusion

The pressure gradient calculated from the plots helped in identifying the fluid types present in the reservoir, which gave knowledge of the hydrocarbon categorization. It is important for the water contact to be known during the early stages of field development.


4. PRESSURE VOLUME TEMPERATURE ANALYSIS


4.1 PVT ANALYSIS OF FLUID SAMPLES GOTTEN FROM AGU FIELD

4.1.1 Introduction

MDT samples were taken from Agu 2 and Agu 3 in reservoir E7000, E7500 and E8000

for laboratory PVT analyses. From the site, Schlumberger transported the reservoir fluids

which they had collected in their pressurized sample chamber to Reservoir Fluid

Laboratory (in PH) for full PVT analysis. At the laboratory, the samples were transferred

from Schlumberger’s sample chambers to the RFL (Reservoir Fluid Laboratory) cylinder

in order to relieve Sterling of the rental charges that would have been incurred. After the

transfer, the following tests were performed on the reservoir fluid sample:

differential liberation test

flash expansion test

viscosity test

compositional analysis

pressure-volume relation

These tests help in determining reservoir fluid properties which are very important in

petroleum engineering computations such as material balance calculations, reserve

estimates, inflow performance calculations and numerical reservoir simulations. Some of

these reservoir fluid properties include;

oil formation volume factor

solution gas oil ratio

viscosity

4.1.2 Objectives

To determine the;

bubble point pressure of the reservoir, formation volume factor and solution gas

oil ratio

viscosity

composition of the reservoir fluid

4.1.3 Results


The differential liberation test simulates the behavior of the reservoir fluids in-situ during

pressure depletion. Table 1 shows the results of the differential liberation test for

reservoir E7000 with initial pressure at 2514psia and bubble point pressure at 1832psia. It

can also be seen that for every pressure change, the formation volume factor, gas volume

factor, deviation factor, solution gas oil ratio, liberated gas oil ratio, specific gravity gas,

gas viscosity and liquid phase density were measured.

Pressure

(psia) FVF (Bo)

Gas Volume Factor

(bbl/mscf)Z

(Z = PV/NRT)Solution

GOR (scf/stb)

Liberated Gas-oil Ratio

(scf/stb)

Specific Gravity Gas

(Air = 1.0000)

Gas Viscosity

(cp)

Liquid Phase

Density (gm/cm3)

5000 1.104 215 0.8504

4500 1.106 215 0.849

4000 1.108 215 0.8473

3500 1.11 215 0.8454

3000 1.113 215 0.8434

Pi 2514 1.116 215 0.8412

2000 1.12 215 0.8384

Pb 1832 1.121 215 0 0.8375

1500 1.103 1.936 0.934 181 34 0.568 0.01473 0.8475

1200 1.09 2.431 0.938 146 69 0.5677 0.01417 0.8535

900 1.079 3.261 0.944 111 104 0.5683 0.01367 0.8583

600 1.067 4.938 0.953 74 141 0.57 0.01324 0.8637

300 1.054 10.061 0.971 35 180 0.5741 0.01289 0.8695

100 1.046 30.758 0.989 12 203 0.588 0.01268 0.8733

15 1.034 207.324 1 0 215 0.6146 0.01254 0.8821

DIFFERENTIAL LIBERATION TEST AT 157°F

Table 1

The PVT parameters used on the field depends on the surface separation conditions,

therefore, the result of the differential liberation test was adjusted to surface separator

conditions at 300psia and 100°F because the highest shrinkage factor was achieved at this

pressure and temperature during the separator flash expansion test.


Table 2 shows the adjusted values for the oil formation volume factor (FVF) and solution

gas oil ratio for reservoir E7000.

Pressure, psi

FVF, bbl/stb

Solution GOR, scf/stb

2514 1.115 212

1832 1.120 212

1500 1.102 178

1200 1.089 143

900 1.078 108

600 1.066 71

300 1.053 32

100 1.045 9

15 1.033 0

ADJUSTED VALUES

Table 2

The values were adjusted using the Lee and Gonzalez method which is represented by the

equation below:

Bo = Bod [Bobf/Bobd]

Rs = Rsif – (Rsid - Rsd) [Bobf/Bobd]

For reservoir E7000,

Bobf = 1.120bbl/stb

Bobd = 1.121bbl/stb

Rsif = 212scf/stb

Rsid = 215scf/stb

Where,

Bofb = Separator flash formation volume factor

Bodb = Bubble Point Oil formation volume factor from differential liberation


Bod = Formation volume factor at pressure from differential liberation

Bo = Adjusted formation volume factor

Rsif = Separator flash solution gas oil ratio

Rsid = differential liberation solution gas oil ratio

Rsd = Solution gas oil ratio at pressure from differential liberation

Rs = Adjusted solution gas oil ratio

The formation volume factor and solution gas oil ratio of reservoir E7000 was plotted

against pressure in figure 1. This plot shows that Bo increases slightly as the pressure is

reduced from initial to bubble point pressure which is due to the fact that the liquid

expands and since the compressibility of the undersaturated oil reservoir is low, the

expansion is relatively small.

Figure 1: figure showing the formation volume factor and solution gas oil ratio of

reservoir E7000


The oil can dissolve more gas if available, then the initial value of the solution gas oil

ratio must remain constant at 212 (scf/stb) until the pressure drops to the bubble point,

when the oil becomes saturated. See figure 1.

The initial value of the oil formation volume factor, Boi is 1.115rb/stb which increases to

1.120rb/stb at the bubble point pressure. This means that initially 1.115rb/stb of oil plus

its dissolved gas will produce one stb of oil. This ratio is actually favorable since Boi is

close to unity which indicates that the oil contains hardly any dissolved gas and reservoir

volumes are approximately equal to surface volumes. The initial solution gas oil ratio is

relatively low at 212scf/stb which indicates that the oil in reservoir sand A is black oil.

To show the effect of viscosity on the oil with respect to the solution gas oil ratio, the

viscosity values were plotted against pressure as shown in figure 2;

Figure 2: Viscosity-pressure relationship for reservoir E7000

At the initial pressure, the viscosity of the oil is low because it is undersaturated with gas

at this point, but at bubble point pressure, the viscosity increases which is as a result of

the fact that the gas comes out of solution with the oil thereby reducing the oil’s mobility.


The differential liberation test was also performed on the E7500 reservoir fluid samples

that were taken to the laboratory. Table 2 below shows the details of the test.

Pressure (psia) FVF (Bo)

Gas Volume Factor (bbl/mscf)

Z (Z = PV/NRT)

Solution GOR (scf/stb)

Liberated Gas-oil Ratio (scf/stb)

Specific Gravity Gas (Air = 1.0000)

Gas Viscosity (cp)

Liquid Phase Density (gm/cm3)

5000 1.107 246 0.8525

4500 1.109 246 0.8510

4000 1.111 246 0.8492

3500 1.114 246 0.8472

3000 1.117 246 0.8450

Pi 2572 1.120 246 0.8428

Pb 2105 1.123 246 0 0.8402

1800 1.112 1.572 0.907 213 33 0.5746 0.01551 0.8449

1500 1.099 1.907 0.917 178 68 0.5693 0.01482 0.8508

1200 1.087 2.413 0.928 144 102 0.5690 0.01423 0.8560

900 1.075 3.252 0.938 108 137 0.5677 0.01372 0.8616

600 1.063 4.950 0.952 73 173 0.5684 0.01328 0.8672

300 1.051 10.088 0.970 36 210 0.5629 0.01293 0.8725

100 1.044 30.882 0.990 13 233 0.5862 0.01277 0.8757

15 1.034 207.996 1.000 0 246 0.6084 0.01259 0.8822

DIFFERENTIAL LIBERATION AT 159°F

Table 3

The result of the differential liberation test was adjusted to surface separator conditions at

300psia and 100°F because a higher shrinkage factor was achieved at this pressure and

temperature during the separator flash expansion test. However, the values of the

formation volume factor and the solution gas oil ratio had to be adjusted to meet surface

separator conditions. For this reservoir,

Bobf = 1.119bbl/stb

Bobd = 1.123bbl/stb

Rsif = 241scf/stb

Rsid = 246scf/stb


These values were used to calculate the adjustment is shown in table 4;

Pressure, psia

FVF, bbl/stb


2572 1.116 241

2105 1.119 241

1800 1.108 208

1500 1.095 173

1200 1.083 139

900 1.071 103600 1.059 69300 1.047 32100 1.040 915 1.030 0

ADJUSTED VALUES

Table 4

In reservoir E7500, as the pressure is reduced from initial to bubble point pressure, Bo

increases slightly. This effect is due to the fact that the liquid expands and since the

compressibility of the undersaturated oil reservoir is low, the expansion is relatively

small. It can therefore be deduced that the initial formation volume factor of 1.116rb/stb

of oil plus its dissolved gas will produce one stb of oil as shown in figure 3.



reservoir E7500

Furthermore, the oil is undersaturated with gas, which means it could dissolve more gas if

it were available, then the initial value of the solution gas oil ratio must remain constant

at 241 (scf/stb) until the pressure drops to the bubble point, when the oil becomes

saturated, see figure 2. The oil in reservoir E7000 is black oil because the initial solution

gas oil ratio is low and within the GOR range for black oil.

The viscosity of the E7500 sample was measured and a graph of viscosity against

pressure was plotted as shown in figure 4.



The viscosity pressure relationship in figure 4 exhibits a similar trend with E7000

reservoir but the rate at which the viscosity increases in E7500 is lower. This is because

the solution gas oil ratio of the oil in reservoir E7500 is higher than that of reservoir

E7000.


Finally, a differential liberation test was conducted for the E8000 reservoir fluid sample.

Table 3 shows the results of this test in detail.

Pressure (psia) FVF (Bo)

Gas Volume Factor (bbl/mscf)

Z (Z = PV/NRT)

Solution GOR

(scf/stb)

Liberated Gas-oil Ratio (scf/stb)

Specific Gravity Gas

(Air = 1.0000)

Gas Viscosity

(cp)

Liquid Phase Density

(gm/cm3)

5000 1.965 1854 0.6012

4820 1.971 1854 0.5992

4520 1.982 1854 0.5959

4128 1.997 1854 0.5914

Pi 3887 2.008 1854 0.5882

Pb 3514 2.026 1854 0 0.5830

3000 1.817 0.827 0.793 1455 399 0.7591 0.02344 0.6137

2500 1.675 0.995 0.794 1161 693 0.7337 0.01996 0.6377

2000 1.561 1.274 0.814 920 934 0.7195 0.01722 0.6602

1500 1.463 1.750 0.839 709 1145 0.7079 0.01523 0.6822

1000 1.376 2.707 0.865 522 1332 0.7254 0.01376 0.7037

500 1.292 5.665 0.905 342 1512 0.7949 0.01247 0.7252

110 1.188 27.381 0.962 158 1696 1.1956 0.01054 0.7459

15 1.070 208.381 1.000 0 1854 2.436 0.0077 0.7525

DIFFERENTIAL LIBERATION AT 161°F

Table 5

The values of the formation volume factor and solution gas oil ratio were adjusted to

surface separator conditions at 300psia and 100°F which resulted in the values shown in

table 6. The values that were used to calculate the adjustment for this reservoir are as

follows;

Bobf = 1.770bbl/stb

Bobd = 2.026bbl/stb

Rsif = 1476scf/stb

Rsid = 1854scf/stb


Pressure, psia

FVF, bbl/stb


3887 1.754 1476

3514 1.770 1476

3000 1.587 1127

2500 1.463 871

2000 1.364 660

1500 1.278 476

1000 1.202 312

500 1.129 155

110 1.038 0

15 0.935 0

ADJUSTED VALUES

These adjusted values were then plotted against pressure as shown in figure 5;


reservoir E8000

In reservoir E8000, the change in the formation volume factor is from 1.754bbl/stb to

1.770bbl/stb which means that 1.754 reservoir barrel of oil plus its dissolved gas will

produce one stb of oil, see figure 5. Also, in this reservoir sand, Boi is not close to one and


this implies that there might be a significant amount of gas dissolved in the oil, so the

reservoir has to be conditioned properly to ensure that a representative fluid sample is

obtained. But on the other hand, the farther away Boi is from one, the more volatile the

oil.

In this same reservoir, Rsi is constant at 1476scf/stb from the initial pressure to the bubble

point pressure. This is because the oil is undersaturated with gas and has the capacity to

dissolve more gas, (figure 5). The solution gas oil ratio is relatively high at 1476scf/stb

which indicates that the oil present in the reservoir sand is volatile oil.

In addition, a graph of viscosity versus pressure was plotted using the measured viscosity

values of the sample and the corresponding pressure. See figure 6;


The viscosity of E8000 at initial pressure and at bubble point pressure is almost the same.

This could be a result of the high solution gas oil ratio, so even at bubble point pressure

the gas that leaves the oil will have very little effect on the viscosity change of the

remaining oil.


4.1.4 Conclusion

The results of the PVT analysis are important in completion designs- how the completion

strings will react to the produced fluids. On the other hand, it helps in deciding the type

of surface facilities to be used for separation when the fluid is eventually produced to

surface.


5. APPENDIX

Tools

Flow coupling

Selective landing nipple


Flow couplings are designed to inhibit erosion caused by flow turbulence. Flow couplings should be installed above and below landing nipples or any other restriction that may cause turbulent flow.

Selective landing nipple is a completion component fabricated as a short section of heavy wall tubular with a machined internal surface that provides a seal area and a locking profile designed to be run in series throughout the wellbore.

Sliding sleeve

Tubing seal divider


The sliding sleeve is comprised of full-opening devices with an inner sleeve that can be opened or closed, using standard wireline methods to provide communication between the tubing and the tubing/casing annulus.

The tubing seal divider is designed to disconnect the tubing string without disturbing the packer setting.

No-go landing nipple

Blast joint


No-go landing nipple is a nipple that incorporates a reduced diameter internal profile that provides a positive indication of seating by preventing the tool or device to be set from passing through the nipple.

Blast joints are installed in the tubing opposite perforation wells with two or more zones. The blast joints are sized to help prevent tubing damage from the jetting action of the zone perforations.

Packer


A packer is a downhole device used in every completion to isolate the annulus from the production conduit, enabling controlled production, injection or treatment. A typical packer assembly incorporates a means of securing the packer against the casing or liner wall, such as a slip arrangement, and a means of creating a reliable hydraulic seal to isolate the annulus, typically by means of an expandable elastomeric element.

Packers are classified by application, setting method and possible retrievability.

Documents

2011CHG0076