VOLUMETRIC RESERVE EVALUATION AND THIRD PARTY ... · Location map of Yasin Block (2768-7) in...

VOLUMETRIC RESERVE EVALUATION

AND

THIRD PARTY CERTIFICATION

OF

HASEEB GAS FIELD

YASIN BLOCK (2768-7)

SIND PROVINCE-PAKISTAN

FOR

HYCARBEX-AMERICAN ENERGY INC.(HYCARBEX INC.)

ISLAMABAD - PAKISTAN

BY

INTEGRATED PETROLEUM CONSULTANTS (PVT.) LIMITEDISLAMABAD - PAKISTAN

GSM, Inc.Texas, USA

(DECEMBER 2007)

H EHycarbex-American Energy, Inc.

I P C a Robert D. Grace Company

VOLUMETRIC RESERVE EVALUATION

AND

THIRD PARTY CERTIFICATION

OF

HASEEB GAS FIELD

YASIN BLOCK (2768-7)

FOR

HYCARBEX-AMERICAN ENERGY INC. (HYCARBEX INC.)

ISLAMABAD – PAKISTAN

BY

INTEGRATED PETROLEUM CONSULTANTS (PVT.) LIMITED House # 209, Street # 49, F-10/4, ISLAMABAD – PAKISTAN Ph.: +92-51-2102068, 2100945-6 Fax: +92-51-2110087 E-mail: [email protected]

GSM, Inc. P. O. Box 50790,

Amarilo, TX 79159-0790 Ph.: +1 806 358 6894

Fax: + 1 806 358 6800 E-mail: [email protected]


Amarilo, TX 79159-0790 Ph.: +1 806 358 6894



Amarilo, TX 79159-0790 Ph.: +1 806 358 6894


LIST OF CONTENTS

Description Page

1. Foreword 1

Scope of work 1

Authority 1

Source of Information 1

2. Executive Summary 4

3. Introduction 7

4. Geological Setting 8

5. Stratigraghy 8

6. Petroleum Geology 11

7. Log Evaluation 14

8. Petrophysical Analysis 15

Petrophysical Data 15

9. Estimation of Reserves 17

Volumetric Reserves of Haseeb Gas Field 17

10. Hydrocarbon Reserves Terminologies 18

Total Gas Reserves 19

Recoverable Gas Reserves 19

11. Gas Analysis 21

12. Drill Stem Test (DST) 22

First Buildup (2 hours) 22

Final Buildup (48 hours) 23

13. Inflow Performance Relationship (IPR) 30

14. Acid Stimulation 32

15. Pressure Buildup Test 41

16. Conclusions and Recommendations 45

Reserve Classification 45

LIST OF FIGURES

Figure 1. Location map of Yasin Block (2768-7) in Jacobabad and Shikarpur Districts,

Sind and Balochistan Provinces, Pakistan

Figure 1(a). Petroleum Activities Map of Yasin Block (2768-7)

Figure 2. Hole Construction Diagram of Haseeb-1 well

Figure 3. Stratigraphic Column of Haseeb-1 well

Figure 4. Depth Structure Map on Top of Sui Main Limstone (SML), Haseeb Structure

Figure 5. Schlumberger’s Elan representing Reservoir Interval of Haseeb-1 well

Figure 6. World Petroleum Congress (WPC) Definition of Reserves

Figure 7. History Plot: First Flow and Final Buildup, Pressure (psia) vs. Time (mins)

Figure 8. Log-Log Plot Pressure and Derivative

Figure 9. Semi-Log Pressure Plot

Figure 10. History Plot: Four Flow and Final Buildup Pressure (psia) vs. Time (mins)

Figure 11. Log-Log Plot Pressure and Derivative and Model

Figure 12. Semi-Log Pressure Plot

Figure 13. Inflow Performance Relationship (IPR)

Figure 14. Pre Acid Stimulation Inflow Performance Relationship (IPR)

Figure 15. Forecasted Post Acid Stimulation Inflow Performance Relationship (IPR)

Figure 16. Actual Post Acid Stimulation Inflow Performance Relationship (IPR)

Figure 17. Comparison of IPR’s

Figure 18. Production from the well for a larger Choke Size

Figure 19. Production from the well for Tubing of larger ID

Figure 20. Pressure and Gas Flow Rates vs. Time

Figure 21. Log-Log Plot dm (p) and dm(p)´ [psi2/cp] vs. dt (hr)

Figure 22. Semi-Log Plot m(p) [psi2/cp] vs. Super Position Time

Integrated Petroleum Consultants (Pvt.) Limited

1

Volumetric Reserve Evaluation and Third Party Certification for Haseeb Gas Field,

Yasin Block (2768-7), Shikarpur District, Sind Province, Pakistan.

FOREWORD Scope of Work

This Study is an estimate of the reserve of Hydrocarbons discovered in the Haseeb Gas Field

of Yasin Block (2768-7) in Sind Province, operated by Hycarbex-American Energy Inc.

(Hycarbex Inc.) as can be seen in the location map. {Figs.1 & 1(a)}

Authority

This Study has been authorized by Dr. Iftikhar A. Zahid, President / Chief Executive of

Hycarbex-American Energy Inc. (Hycarbex Inc.).

Source of Information

This evaluation of reserves is based on data provided by Hycarbex-American Energy Inc.

(Hycarbex Inc.). We did not carryout any field examination of assets.

The list of data examined is as follows:

• All logs data

• Lithology

• Depth structure map

• Schlumberger’s Elan interval of Haseeb-1 well

• Drill Stem Test (DST) report

• Acid Stimulation data

• Absolute Open Flow test (AOF)

• Well test report

• Composition of gas

Integrated Petroleum Consultants (Pvt.) LimitedI PC

2

Fig

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HERITAGE

Figure 1(a) Petroleum Activities Map showing Yasin Block (2768-7)

INDIA

Sind

Balochistan

Active Exploratory Well Location

Active Development Well Location

Active Rig Location

Current 3D Seismic Location3D

Legend

3


4

EXECUTIVE SUMMARY

The Haseeb Gas Field is located within the Yasin Block (2768-7) in Jacobabad-Khairpur

High, Lower Indus Basin, onshore Pakistan.

Gas was discovered at the field in 2005 through the Haseeb-l well, which encountered gas in

the Sui Main Limestone (SML) of Eocene age. The structure is gently dipping and well

defined as a NNW-SSE oriented compressional anticlinal fold.

Initial testings proved a good quantity of gas. Subsequently, to increase the gas rate from the

well, an acid treatment production enhancement job was undertaken by M/s Schlumberger

who tested well at double gas flow rate and reported that the well has a flow capacity of

28.5 MMSCFD.

A quick stabilization of shut-in pressure and a small difference between the last flowing

pressure and the shut-in pressure indicate a very high permeability reservoir.

This report has as its main focus, an estimation of gas reserves of the field (in P90, P50 and

PI0 categories). The report also offers some petroleum engineering comments aimed at

obtaining optimum gas production and maximum recovery. The data used in the preparation

of these estimates of field reserves were provided by Hycarbex-American Energy Inc.

(Hycarbex Inc.) and data taken from our archives which provided regional integrated analysis

to make this study rational and authentic.

The study confirms recoverable gas reserves from the Haseeb field at around 196 BSCF-P10

category and at 174 BSCF-P90 category. High reservoir pressures at various choke sizes

indicate that the initial plateau production period be around 10-15 years at a optimal gas flow

rate of 12-18 MMSCFD per well and a field flow rate with multiple wells at around

30-35 MMSCFD.

The gas field is commercially viable and merits development for the sale of gas. Nearby

infrastructure (gas buyer pipelines) and gas buyers willingness to take gas to meet acute

demand growth market, are added justifications for its development.


5

Table-1

Well Name Haseeb-1 (discovery well)

Well Type Gas well

Concession Area Yasin Block (2768-7), Balochistan and Sind Provinces, Pakistan

Location Shikarpur District, Sind Province, Pakistan

Seismic Location On station # 161 of Seismic Line 2005-Y-06-EXT

Co-ordinates

Latitude 28° 01' 16.61989" N

Longitude 68° 38' 39.85096" E

Elevation 60 Meters AMSL

KB Elevation 64.5 Meters AMSL

Objective Sui Main Limestone Formation

Spud Date 25th March 2005

Date Reached TD 19th April 2005

Total Depth 1507 meters

Formation at TD Ranikot Formation (Paleocene)

Casing Liner 7" Liner

Drilling Contractor OGEC Krakow

Drilling Rig RR600 Krakow, Mechanical Land Rig

Data Logging Unit Oil & Gas Development Company Limited

Mud Engineering Services MI SWACO

Cementing Services Halliburton

Electrical Logging & Testing Schlumberger

Casing Services Al-Masaood

Completion 3 ½˝ tubing + S.S.S.V.

Completion Services Baker Oil Tools

Hole Construction diagram of Haseeb-1 well is shown in Fig. 2.


6

Figure 2 Hole Construction Diagram of Haseeb-1 well.

CSG DATA3OD 13 /88ID 12 /13

WT (lb/ft) 54.5Grade K- 55Collapse (psi) 1131Burst (psi) 274013 3/8’’ CSG.SEQUENCEF.S 0.59m27 jt, 54.5(bs/ft) 360.97mTotal 361.56mShoe at 361mFm. at shoe Siwalik

5OD 9 / m813ID 8 / m16

WT (Ib/ft) 40.0Grade K- 55Collapse (psi) 2566Burst (psi) 39439 5/8” CSG. SEQUENCEF.S 0.53 m01 Joint 12.61 mFloat Collar 433 0.44 m87 Joint 1044.24 mTotal 1057.82 mShoe at 1056.0 mFormation at shoe Ghazij

Top of Liner 992 m7” LINER CSG. SEQUENCEBOX UP F.S 0.95 m02 jt, 29.0(Ibs/ft) 24.90 mL. Collar 0.31 m11 jt, 29.0(Ibs/ft) 137.33 mHanger 1.44 mS/S 0.45PBR 1.93 mR/Tool 1.70 mX-O 0.48 mTotal 169.49 mShoe at 1160 m

Formation = SUI MAIN LIMESTONE

DRILLING/CEMENT DATA

Spud-in date 25- March-2005Mud Weight 8.8 - 8.9 ppgBit used 02Time 08 DaysROP 6.00 m/HrFlow Line Temp- 30 °C

Hole Deviation 1°Water 10 bblLead Cement Slurry 126 bbl

Wt. of Lead Slurry 12.50 ppgTail Slurry 162.35 bblWt of Tail Slurry 15.80 ppg

Performed Top Cement Jobwith 12 bbl cement

Mud Weight 9.3 - 9.9 ppgBits used 02Time 10 DaysROP 9.95 m/HrFlow Line Temp. 61.5° CHole Deviation 0.5° - 3.0°Spacer of 11 ppg 28 bblCement Slurry 237.5 bblWt. of Cement Slurry 15.80 ppg

Mud Weight 8.8 ppg - 9.2 ppgBits used 02Time 10 daysROP 4.39 m/HrFlow Line Temp. 61° CW.L. Log Temp. 84° CHole Deviation 0.5 - 0.75°CaCo3 Hi-Vis Pill 25 bblSpacer 17 bblB. Mix Slurry 35.75 bbl

Bottom Cement Plug 1260 m to 1160 m

TD 1507 M

HOLE CONSTRUCTION DIAGRAM OF HASEEB-1 WELL

20” Conductar @ 30 m

Top ofLiner @992 m


7

INTRODUCTION

The Haseeb Gas Field was discovered in the year 2005 in Yasin block (2768-7) by a Joint

Venture comprising Hycarbex-American Energy Inc. (Hycarbex Inc.) Operator,

Government Holdings Private Limited (GHPL) and Techno Petroleum Private Limited

(TPPL). The block is located mainly in the Jacobabad and Shikarpur districts of Sind

Province, Pakistan. A small portion of the north and northwest Yasin block lies in the

Balochistan Province. The concession falls in the Prospectivity Zone III as defined by 1998

Petroleum Policy of Ministry of Petroleum and Natural Resources, Pakistan. Zone III is lower

risk area with high potential of discovering hydrocarbon reserves.

The working interest of the Joint Venture partners is as follows:

Hycarbex-American Energy Inc. (Hycarbex Inc.) - Operator 85%

Government Holdings Private Limited (GHPL) 5%

Techno Petroleum Private Limited (TPPL) 10%

The discovery well (Haseeb-1) was drilled to a TD of 1507 m into Paleocene Ranikot

Formation. The plug back depth was 1260 m-1160 m. No core was cut in the well. The DST

performed by Schlumberger in three intervals of a promising 35 m thick log-read zone of

Eocene Sui Main Limestone proved the presence of hydrocarbons (primarily Methane with

some inert gases) in the well. The limestone reservoir containing the gas is highly porous.

The porosities in the reservoir exceed 20% and are a combination of matrix and fracture

porosity.

A study has been conducted to provide a realistic volumetric assessment of the Original Gas

in Place (OGIP), total gas recovery, and certify the reserves of the Haseeb Gas Field. It is to

be appreciated that most likely economic recovery or time frame of economic abandonment

depend upon field development strategy, gas disposal / sale considerations, reservoir

properties and drive mechanism. These factors govern the total gas recovery which could be

actually achieved. However based on our technical analysis, we believe that there is a

sufficient volume of gas in the field that could be produced over an extensive time period and

which justifies development of the field on a commercial basis.


8

GEOLOGICAL SETTING

The basinal history of the Study area is related mainly to rifting and break up of Gondwana in

the Jurassic period. In the Cretaceous, East Gondwana (India-Antarctica-Australia) separated

from the West Gondwana (Africa-South America). The Indian plate separated from East

Gondwana in Aptian time (120 ma). At the end of the Cretaceous / Early Paleocene, the

Seychelles and Madagascar separated from India with associated faulting accompanied by

basaltic flows (Deccan volcanics) in the southern part of the Lower Indus Basin. The regional

base Tertiary unconformity is due to thermal doming associated with the separation of the

Seychelles and Madagascar from India. After the Paleocene there was a continuing oblique

convergence of India and Asia throughout Tertiary time and the collision of India with Asia

caused a westward tilting of the entire region.

The Jacobabad-Khairpur High on which the Study area is located, developed by domal

uplifting in during the Early Cretaceous and later on along deep seated faults in the Late

Cretaceous and Paleocene. During Eocene time there was submergence and by the Oligocene

it was uplifted again and then leveled by molasse deposition in Miocene to Recent time in the

newly developed alluvial fans of a major river system due to the uplift of the Himalayas. On

the Jacobabad-Khairpur High, Eocene carbonates (Sui Main Limestone) are widely

distributed and form good hydrocarbon reservoirs.

The presence of Jurassic rocks in the area show deposition during rifting. The drifting of East

Gondwana began in the Early Cretaceous and with continued deposition on the marginal

slopes of the northward drifting Indian plate till early the Tertiary. The collision of India and

Asia took place in phases at the end of the Cretaceous and the Tethys became closed during

the Paleocene-Eocene. The spur of the Tethys is now marked by exposures of ophiolites

along the Axial Belt.

STRATIGRAPHY

The stratigraphic units in the area were laid down in response to the tectonic evolution of the

Indus basin. There were pre-rift, rift, drift and collision phases which controlled the

sedimentation and the deposited sequences were the product of a combination of plate

movements, global sea level changes and tectonic activity.

During pre-rift phase the sediments were laid down in a warm, arid environment, followed by


9

glaciation and advent of another warm cycle. All these pre-rift sediments are exposed in the

Salt Range in the Upper Indus Basin.

The rifting started in the Jurassic and the sediments were deposited along the leading edge of

the plate in a marginal sag type of basin. Chiltan Limestone is the key product of this phase in

the study area.

From Late Jurassic to Cretaceous time drifting of the plate influenced sedimentation and

deposition of Sembar, Goru, Mughal Kot and Pab clastics took place in the area.

During the early collision phase in the Paleocene, Ranikot clastics were deposited followed

by Eocene carbonates including the important Sui Main Limestone reservoir of the study

area.

During the late collision phase, influxes of eroded material from rising mountain ranges along

the collision site were dumped as molasses in a continental environment. The stratigraphic

package of the Jacobabad-Khairpur High includes Mesozoic (Alozai, Loralai, Chiltan,

Sembar, Goru, Parh, Mughal Kot and Pab formations) and Tertiary and Quaternary (Ranikot,

Sui Main, Ghazij, Kirthar and Siwalik) sediments.

The drilled stratigraphy in Haseeb-1 well is shown in Fig. 3 and includes Ranikot, Sui Main,

Ghazij, Kirthar, Siwalik and Alluvium.


10

Figure 3 Stratigraphic Column of Haseeb-1 well.


11

PETROLEUM GEOLOGY

The Haseeb Gas Field is located in the Lower Indus Basin within the Jacobabad-Khairpur

High tectonic feature.

The structure was delineated by a seismic survey conducted in 2004-2005. It is a well

formed, gently dipping anticline oriented in a NW-SE direction (Fig. 4). The size of the

structure is about 15 sq km and its vertical closure is around 69 m. Two normal faults cut the

structure in the north forming a narrow graben. The maximum throw of the faults is

15m-20m.

The Eocene Sui Main Limestone, which was the primary target in Haseeb-1 well and which

has been found productive in the vicinity gas fields was encountered at 1048 m depth from

KB. It is 239 m thick and overlies Paleocene clastic rocks of the Ranikot Formation in which

the well reached its TD. The Eocene shale dominated Ghazij Formation was 746 m thick and

was overlying the Sui Main Limestone. This shaly formation is the regional seal for the Sui

Main Limestone reservoir. Ghazij shales are overlain by Middle Eocene Kirthar carbonates,

Miocene-Pliocene Siwalik molasse unit and Alluvium. The drilled stratigraphic sequence is

shown in Fig. 3. The Sui Main Limestone, which is a producing gas reservoir in a number of

small and large fields in the vicinity of the Haseeb Gas Field including the world class giant

Sui Field of Pakistan Petroleum Limited was named after the subsurface type section at Sui

and Qadirpur Gas Field of Oil & Gas Development Company Limited. It consists mainly of

cream colored, chalky limestone with brownish limestone, white to brownish grey calcareous

and pyretic shale. Detailed facies analysis indicates the following facies development in the

area:

1. Green algal lime packstone / wackestone to grainstone

2. Large benthic foraminiferal lime packstone to grainstone

3. Large foraminiferal wackestone to packstone

4. Planktonic foraminiferal mudstone to wackestone / packstone

5. Small benthic foraminiferal packstone wackestone

6. Echinoderm wackstone

7. Dolomitic limestone / calcareous dolomite

8. Terrigenious mudstone

The common faunal assemblage includes forams, algae, echinoids, bivalves, bryozoans and

gastropods.


12

Figure 4 Depth Structure Map on Top of Sui Main Limestone (SML), Haseeb Structure

68°37'

68°37'

68°38'

68°38'

68°39'

68°39'

68°40'

68°40'

28°00'

28°00'

28°01'

28°01'

28°02'

28°02'

28°03'

2004-Y-09

2005-Y-13

2004-Y-08

2005-Y-12

2005-Y-06 EXT -W

2005-Y-11

2004-Y-10

2004-Y-01

GWC AT (-) 1052 (1117 M from KB)

2005

-Y-1

5

2004

-Y-0

2

-105

2-105

0

-104

0-103

0-102

0

-101

0

-100

0

-990

-98520

05-Y

-14

HASEEB WELL # 1 TOP SML AT (-) 983 M

(1048 M from KB)

N-1050

-1060

GR

AB

EN

28°03'

HYCARBEX-AMERICAN ENERGY INC.(Hycarbex Inc.)

YASIN BLOCK (2768-7)(Balochistan and Sind Provinces, Pakistan)

HASEEB STRUCTUREShikarpur District, Sind Province, Pakistan

DEPTH STRUCTURE MAP ON

Contour Interval 10 M

Depth Contour

Normal Fault

Gas Water Contact

SCALE1: 25,000

0 500 1000

-1010

-1052

Top Sui Main Limestone (SML)


13

The Sui Main Limestone in the area was deposited on a shallow water carbonate platform

with occasional influx of clastic material. The green algal facies represents deposition in the

photic zone with low to moderate energy and warm marine conditions. Larger foram-bearing

grainstones were laid down in shallow marine high-energy environment on shoals in middle

shelf. Planktonic foraminiferal facies indicates open marine (outer shelf) environment below

wave base. Dolomitic limestones were deposited in restricted inner shelf conditions. The

terrigenious mudstones are indicative of the quite outer shelf environment. The depositional

cycle of Sui Main Limestone shows an upward shallowing sequence. The upper part of the

unit indicates flooding to more basinal conditions.

The reservoir properties of the Sui Main Limestone indicate development of high porosity

due to their buildup on a stable platform. The timely accumulation of gas helped in

preservation of good porosity. The porosities in the Sui Main Limestone include matrix

microporosity, mouldic porosity, vuggy porosity, intragranular porosity and intercrystalline

porosity. Fracture porosity is associated with the reservoir but is not the dominant contributor

to the development of effective reservoir porosity and permeability in the area. The average

porosities along the paleo-shelf edge trend are 16 %. In the Sui field the porosities range from

6.7 to 28.4 %. The reservoir zone within the Sui Main Limestone in the Haseeb field shows

more than 20 % porosity, which indicates good existence and preservation of porosity due to

timely entrapment of gas.

The source rocks responsible for generation of the gas in the area are the organic rich

Cretaceous shales belonging to the Sembar/Goru formations. The migration of gas could have

taken place along shear faults or fracture planes created by compression in the Sui Main

Limestone and underlying strata.

Thick Ghazij shales immediately above the Sui Main Limestone are the regional top seal and

provide an adequate sealing mechanism to the gas filled carbonate reservoir. Among the inert

gases found associated with Methane, Nitrogen generally comes up along faults. Carbon-

dioxide, however is the product of the surface water infiltration along unconformities, like the

one above the Sui Main Limestone.


14

LOG EVALUATION

The following wireline logs were run by Schlumberger in the Haseeb-1 well:

• HALS-BHC-MCFL-TLD-CNL-GR-SP

• MDT-GR

• CBL-VDL-GR-CCL in 7” Liner

• CBL-VDL-GR-CCL in 9 5/8” Casing

From logs, it is evident that the pay zone in the Sui Main Limestone ranges from 30 to 35 m

in thickness. The porosities are high and within the perforated zone range from 20 % to 23 %.

The porosities of each perforated zone are tabulated below:

Perforated Interval

Meters

Thickness

Meters

Lithology

Porosity

%

Water Saturation

%

1082-1084 2 Limestone 20 36

1088-1093 5 Limestone 21 38

1097-1100 3 Limestone 23 47

The water saturation in the pay zone ranges from 36 to 46 %. The water saturation in the

perforated zones is shown in above table.

The Formation Volume Factor is in the range of 105-113 SCF/cuft

In the absence of a production history, material balance has not been considered however;

care has been taken to use a range of values of reservoir parameters to arrive at realistic

volumes of gas in different categories of reserves.

The Parameters used in the estimation of reserves and the hydrocarbons in place are tabulated

in Table 2 and 3.


15

PETROPHYSICAL ANALYSIS

Wireline logs were run. The analyzed well is producing hydrocarbon from Sui Main

Limestone Formation of Eocene age.

The net pay of the well was calculated from Open Hole Logs and incorporated with Elan

(Fig. 5). The thickness of net pay in the Sui Main Limestone is approximately 33 m

(108.273ft). Porosity is 23 %. Since no core data was available, only log calculated porosity

was used in calculation of reserves. Water saturation of 32 % is used in the reserves

calculation.

Table-2

Petrophysical Data

Well Name

Producing Formation

Net Pay

ft

Porosity

%

Water Saturation

%

Haseeb-1 Sui Main Limestone 108.273 23 32


16

Figure 5 Schlumberger’s Elan representing Reservoir Interval of Haseeb-1 well


17

ESTIMATION OF RESERVES

Estimation of hydrocarbon reserves in this Study has been carried out following standard

geological and reservoir engineering practices employed by the industry.

The reserves have been estimated volumetrically. The details are given in Table-3. It should

be taken into account that these reserves do not exclude inert gases for the economic

evaluation. The n-Pentane and lighter hydrocarbon fraction should be considered and the

inert portion of the gas eliminated to reach a real asset. The gas analysis is given in Table-4.

Table-3

Volumetric Reserves of Haseeb Gas Field

Formation Sui Main Limestone

Constant 43560

Area (Acres) 3583

Net Pay Thickness (hn) ft 108.273

Porosity (φ) 23%

Water Saturation (Sw) 32%

Gas Saturation (Sg) (1-Sw) 68%

Formation Volume Factor (Bgi)

(Scf/cuft)

104 0.0096

Geometric Correction Factor 0.95

Gas Gravity (g/ce) 0.705

GIIP (BSCF) 261

Recovery Factor 0.75

Recoverable Reserves (BSCF) 196


18

HYDROCARBON RESERVES TERMINOLOGIES

Nomenclatures adopted by various agencies in the estimation of hydrocarbon reserves are

found to be highly diverse. A specific philosophy and the objective of the estimation is seen

to be the main guide.

Hydrocarbon being a natural resource is subject to estimation of its reserves like any

economic mineral. In the fluid form, it is estimated as stock tank barrels of oil (STBO) and in

the gaseous phase in standard cubic feet (SCF). The commercial evaluation and economic

aspect of hydrocarbon reserves guide both exploration and exploitation activities.

There is not a single standard procedure to classify the estimated resource of hydrocarbon

that could be applied on a global scale and understood by regulatory agencies, financial

institutions and public at large with equal measure of comprehension.

Generally the three categories of reserves that are accepted in the industry are: -

1. Proved Reserves (P90)

2. Probable Reserves (P50)

3. Possible Reserves (P10)

The Proved reserves are based on well production data and other reservoir parameters. The

Probable reserves are based on engineering and reservoir modeling of pertinent data and have

a very high degree of certainty while the Possible reserves are where investigations support

further economic investment.

All these categories of reserves represent different level of probabilities of finding and

producing these reserves.


19

The World Petroleum Congress (WPC) classification of reserves with different probabilities

accepted by petroleum industry and accepted worldwide is shown in Fig. 6 and subsequently

followed in this deterministic Volumetric Reserves Estimation Study.

Following are the Gas In Place and reserves:

Total Gas In Place

Possible Gas In Place (P10) = 261 BSCF

Probable Gas In Place (P50) = 230 BSCF

Proven Gas In Place (P90) = 217 BSCF

Ultimate Recoverable Gas Reserves By Reserve Classification

Recoverable Possible Reserves (P10) = 261 x 0.75 = 196 BSCF

Recoverable Probable Reserves (P50) = 230 x 0.77 = 177 BSCF

Recoverable Proven Reserves (P90) = 217 x 0.80 = 174 BSCF


20

Figure 6 World Petroleum Congress (WPC) Definition of Reserves

PR

OB

AB

ILIT

Y P

ER

CE

NTA

GE

PROVEN PRB. POSSIBLE

RESERVES (MMBO)

3P2P1P

600 %

10 %

20 %

30 %

40 %

50 %

60 %

70 %

80 %

90 %

100 %

65 70 75 8580


21

GAS ANALYSIS

Gas Analysis by Core Laboratories International B. V. – Pakistan

Component Mole % Weight %

Hydrogen Sulphide 0.00 0.00 Carbon Dioxide 3.82 8.24 Nitrogen 20.58 28.23 Methane 73.29 57.54 Ethane 1.17 1.72 Propane 0.30 0.66 i-Butane 0.08 0.23 n-Butane 0.10 0.30 Neo-Pentane 0.00 0.01 i-Pentane 0.05 0.18 n-Pentane 0.03 0.10 Hexanes 0.05 0.20 Heptanes plus 0.53 2.59 Total 100 100

Note: 0.00 means < 0.006 Calculated Properties by ISO6976: 1995 (F) Ideal Relative Density 0.705 (Air = 1.000) Ideal Gross Heating Value 807 BTU per cuft Dry Gas metered & combusted @ 14.65 psia, 60° F Ideal Net Heating Value 728 BTU per cuft Dry Gas metered & combusted @ 14.65 psia, 60° F


22

DRILL STEM TEST (DST) A Drill Stem Test on the Haseeb-1 gas well was carried out by Schlumberger on April 27,

2005 to test the potential of the well and to estimate the reservoir properties like permeability

and skin etc. The DST was run in the well and the test was conducted as follows:

1st Flow 32/64" 30 minutes (0.5 hours)

1st Buildup 32/64" 120 minutes (2.0 hours)

2nd Flow 20/64" 270 minutes (4.5 hours)

3rd Flow 24/64" 240 minutes (4.0 hours)

4th Flow 28/64" 240 minutes (4.0 hours)

Final Flow 32/64" 240 minutes (4.0 hours)

Final Buildup 2880 minutes (48 hours)

The buildup data in the first buildup is stable and reliable. The second buildup shows an

unstable pressure trend after a few hours of being shut-in.

The reliable pressure periods have been used in the interpretation (Fig. 7).

First Buildup (2 hours)

The well was flowed for approximately half an hour at a 32/64" choke size and then shut-in

with a downhole pressure control valve (PCT) for a pressure buildup for 2 hours. Results of

this test are as follows:

Permeability thickness k x h = 1760 md.m (inner zone)

Permeability = 59 md (using a thickness of 30 m from MDT and OH logs)

Skin = 1.2

Ri = 12 m

M = 0.028

D = 0.028

Log-log pressure and Semi-log pressure plots are presented in Figs 8 and 9.


23

Final Buildup (48 hours)

After the first buildup for 2 hours, the well was flowed at four rates (approximately for

4 hours) as mentioned earlier and the well was shut-in for a buildup for 48 hours.

There was rise and drop in pressure after some hours, for this reason only the first hours of

the buildup has been interpreted. Results of this test are shown below:

Permeability thickness (k x h) = 1500 md.m (inner zone)

Permeability (k) = 50 md (using a thickness of 30 m from MDT and OH logs)

Skin = 12 Ri = 15 m M = 0.023 D = 0.023

The history plot is shown in Fig. 10 Log-log pressure and the semi-log pressure plots are presented in the Figs 11 and 12.


24

Fig

ure

7

His

tory

Plo

t: F

irst

Flo

w a

nd F

inal

Bu

ild

up

, Pre

ssur

e (p

sia)

vs.

Tim

e (m

ins)

1670

1660

1650

1640

1780

1800

1820

1840

1860

1880


25

Fig

ure

8

Log

-Log

Plo

t P

ress

ure

and

Der

ivat

ive

and

Mo

del

1E+

7

1E+

6

1E+

5

1000

0

1000

1E-3

0.01

0.1

110

100

1000


26

Fig

ure

9

Sem

i-L

og

Pre

ssur

e P

lot

2.07

E+

8

2.05

E+

8

2.03

E+

8

-2.4

-2-1

.6-1

.2-0

.8-0

.4


27

Fig

ure

10

H

isto

ry P

lot:

Fo

ur

Flo

ws

and

Fin

al B

uil

du

p, P

ress

ure

(psi

a) v

s. T

ime

(min

s)

1670

1650

1630

1610

1590

1570

2500

3000

3500

4000

4500

5000

5500


28

Fig

ure

11

Log

-Log

Plo

t P

ress

ure

and

Der

ivat

ive

and

Mo

del

1E+

9

1E+

8

1E+

7

1E+

6

1E+

5

1000

0

1000

1E-3

0.01

0.1

110

100

1000

1000

01E

+5


29

Fig

ure

12

Sem

i-L

og P

ress

ure

Plo

t

2.06

E+

8

2.02

E+

8

1.98

E+

8

1.94

E+

8

-3.5

-3-2

.5-2

-1.5

-1-0

.5


30

INFLOW PERFORMANCE RELATIONSHIP (IPR)

A Jones 4 point IPR was constructed to estimate the potential of the Haseeb-1 gas well. The following parameters were used to construct the IPR. PVT Data: Gas Gravity 0.68 CO2 3% N2 14% Surface rates and downhole pressure are shown in the Table-4 below The Absolute Open Flow Potential (AOFP) for the Haseeb-1 is 46 MMSCFD as shown on Fig. 13. Table-4

Choke Size INCH

Gas Rate MSCFD

Downhole Pressure psia

20/64" 3060.00 1630.11 24/64" 4000.00 1613.50 28/64" 5720.00 1593.00 32/64" 7320.00 1573.11

On initial testing a negligible amount of water was produced which was not encountered

during pre / post stimulation flows. This suggests that the water probably was drilling fluid

and not the formation water.


31

Fig

ure

13

In

flow

Per

form

ance

Rel

atio

nshi

p (I

PR

)

Gas

Rat

e, M

scf/

D

Infl

ow (

1)

Bottomhole Pressure, psig

50000

1

4000

030

000

2000

010

000

00

500

1000

1500

2000


32

ACID STIMULATION The Acid Stimulation job was conducted by Schlumberger on the Haseeb-1 well on October

22, 2005. The objective was to increase the productivity of the well by matrix stimulation.

The report compares the productivity of the well before and after the Acid Stimulation job.

1. Pre Acid Stimulation Inflow Performance Relationship. (IPR) (Fig. 14)

2. Forecasted Post Acid Stimulation Inflow Performance Relationship. (IPR) (Fig. 15)

3. Post-Acid Stimulation Inflow Performance Relationship (IPR) (Fig. 16)

Pre Acid Stimulation Inflow Performance Relationship Table-5

Sr. No.

Choke Size INCH

Gas Rate MSCFD


1 20/64" 3060 1638.8

2 24/64" 4000 1622.2

3 28/64" 5720 1601.7 4 32/64" 7320 1581.7

Forecasted Post Acid Stimulation Inflow Performance Relationship (IPR) Fig.15 was

constructed using following parameters:

Reservoir pressure 1673 psia,

Reservoir permeability 50 md

Reservoir thickness 30 m

Skin 0

Post Acid Stimulation Inflow Performance Relation, Flow Rates and bottomhole pressure are

shown in Fig. 16.


33

Fig

ure

14

Pre

Aci

d S

tim

ula

tion

Inf

low

Per

form

ance

Rel

atio

nsh

ip (

IPR

)

500 0

010

000

1000

1500

2000

Bottomhole Pressure, psia

Gas

Rat

e, M

scf/

D

Pre

Aci

d I

PR

Ou

tflo

w

2000

030

000

4000

050

000

Con

d U

nloa

ding

Rat

e

Infl

ow (

1)

Infl

ow @

San

dfac

e (

1)O

utfl

ow (

A)

Wat

er U

nloa

ding

Rat

eM

ax E

rosi

onal

Rat

e


34

Reg

: D

owel

l S

chlu

mbe

rger

Inc

. -

Aut

hori

zed

Use

r

Ou

tflo

w

Pos

t A

cid

For

ecas

t IP

R

2000

1500

1000

500 0

010

000

3000

040

000

5000

060

000

7000

0

Ga

s R

ate

, Msc

f/D

2000

0

Fig

ure

15

For

ecas

ted

Po

st A

cid

Sti

mul

atio

n I

nfl

ow

Per

form

ance

Rel

atio

nsh

ip (

IPR

)

8000

0

Bottomhole Pressure, psia Con

d U

nloa

ding

Rat

e

Infl

ow (

1)

Infl

ow @

San

dfac

e (

1)O

utfl

ow (

A)

Wat

er U

nloa

ding

Rat

eM

ax E

rosi

onal

Rat

e


35

Fig

ure

16

Act

ual

Po

st A

cid

Sti

mul

atio

n I

nfl

ow

Per

form

ance

Rel

atio

nsh

ip (

IPR

)

Ou

tflo

w

Pos

t A

cid

Sti

m I

PR

1800

1700

1600

1400

030

000


Gas

Ra

te, M

scf/

D

1500

5000

1000

015

000

200

0025

000

Reg

: D

owel

l S

chlu

mbe

rger

Inc

. - A

utho

rize

d U

ser

Con

d U

nloa

ding

Rat

e

Infl

ow (

1)

Infl

ow @

San

dfac

e

(1)

Out

flow

(A

)

Wat

er U

nloa

ding

Rat

eM

ax E

rosi

onal

Rat

e


36

Fig

ure

17

C

om

pari

son

of I

PR

’s

Infl

ow

Ga

s R

ate,

Msc

f/D

Mul

tipl

e S

ensi

tivi

ties

Reg

: D

owel

l S

chlu

mbe

rger

Inc

.-A

utho

rize

d U

ser

Infl

ow @

San

dfac

e (1

)

Out

flow

(A

)

Cas

e 2

(2)

Infl

ow (

1)

Cas

e 3

(3)

Con

d U

nloa

ding

Rat

eW

ater

Unl

oadi

ng R

ate

1000

00

1000

1200

1400

1600

1800

Bottomhole Pressure, Psia

2000

2400

2200

2000

030

000

4000

0

Pre

Aci

d I

PR

Pos

t A

cid

Sti

m I

PR

Ou

tflo

w

Max

Ero

sion

al R

ate

Pos

t A

cid

For

ecas

t IP

R


37

After Acid Stimulation Productivity was measured for different choke sizes. These are

summarized in Table-6 and the IPR is shown in Fig.17.

Table-6

Sr. No.

Choke Size INCH

Gas Rate MSCFD


1 20/64" 3460 1669.5

2 24/64" 4870 1668.6

3 28/64" 6650 1667.4 4 32/64" 8800 1666.2 5 36/64" 10400 1664.9

All cases of the Inflow Performance Relationship (IPR) have been plotted together i.e. pre

acid stimulation, forecasted post-acid stimulation and post acid stimulation. It can be seen

that the productivity of the reservoir has been improved dramatically. The vertical lift

performance curve (Outflow A) for a wellhead pressure of 1430 psi. Pre-acid stimulation

flow rates were 4000 MSCFD and increased to 10000 MSCFD after acid stimulation. This

can be seen from Fig. 17.

The flow can be increased if the choke size is increased. (Fig. 18)

The effect of the acid stimulation is shown in Table-7.

Table-7

Wellhead Pressure

psi

Pre Acid Stimulation Flow Rates

MSCFD

Post Acid Stimulation Flow Rates

MSCFD

1430 4000 10000

1200 14000 22500

1000 18000 28500


38

Fig

ure

18

P

rod

uct

ion

fro

m t

he w

ell

for

a la

rger

Cho

ke S

ize

2000

010

000

080

0

1000

1200

1400

1600

Bottomhole Pressure, Psia

1800

2000

2200

3000

040

000

5000

0

Infl

ow

Ou

tflo

wG

as R

ate

, Msc

f/D

Mul

tipl

e S

ensi

tivi

ties

(A)

1432

.0

(B)

1200

.0

(C)

1000

.0

Wel

lhea

d P

ress

ure,

psi

g

Reg

: D

owel

l S

chlu

mbe

rger

Inc

.-A

utho

rize

d U

ser

Ou

tflo

w

Infl

ow @

San

dfac

e (1

)

Out

flow

(A

)

Cas

e 2

(2)

Cas

e 2

(B

)

Cas

e 3

(C

)

Infl

ow (

1)

Cas

e 3

(3)

Con

d U

nloa

ding

Rat

eW

ater

Unl

oadi

ng R

ate

Max

Ero

sion

al R

ate

AB

C

Pos

t A

cid

Sti

m I

PR

Pos

t A

cid

For

ecas

t IP

R

Pre

Aci

d I

PR


39

The effect of tubing size is shown in Fig.19 and Table-8, the flow rates can be doubled, by

increasing the tubing size.

Table-8

Tubing ID

INCH

Pre Acid Stimulation Flow Rates

MSCFD

Post Acid Stimulation Flow Rates

MSCFD

2.790 4000 10000

3.920 6700 25000


40

Fig

ure

19

Pro

duct

ion

from

the

wel

l fo

r T

ubin

g of

lar

ger

ID

1900

1

Pos

t A

cid

For

ecas

t IP

R

Pre

Aci

d I

PR

1500

1600

1700

1800

1400

1300

1200

010

000

2000

030

000

4000

0

Infl

owO

utf

low

(A)

2.75

0

(B)

3.92

0


Mul

tipl

e S

ensi

tivi

ties

Tub

ing

ID, i

n

Reg

: D

owel

l S

chlu

mbe

rger

Inc

.-A

utho

rize

d U

ser

Ou

tflo

w

Infl

ow @

San

dfac

eO

utfl

ow (

A)

Cas

e 2

(2)

Cas

e 2

(B

)

Infl

ow (

1)

Cas

e 3

(3)

Con

d U

nloa

ding

Rat

eW

ater

Unl

oadi

ng R

ate

Max

Ero

sion

al R

ate

Tu

bin

g ID

2.7

90”

Tu

bin

g ID

3.9

20”

Pre

Aci

d S

tim

IP

R

Gas

Ra

te, M

scf/

D


41

PRESSURE BUILDUP TEST

The well test was conducted on the Haseeb-1 well between 24 October and 27 October 2005.

The test was conducted in the following sequence.

Initial flow 120 Minutes (2.00 hours)

Initial buildup 1354 Minutes (22.58 hours)

1st Flow 20/64" 258 Minutes (4.30 hours)

2nd Flow 24/64" 240 Minutes (4.00 hours)

3rd Flow 28/64" 240 Minutes (4.00 hours)

4th Flow 32/64" 240 Minutes (4.00 hours)

5th Flow 36/64" 240 Minutes (4.00 hours)

Gauge pressure from this test and the flow rates prior to buildup are shown in Fig. 20. The

last flowing bottom hole pressure is 1665 psia. The reservoir pressure after buildup is 1673

psia. The difference between the last flowing pressure and the final buildup is just 8 psi. The

well was flowing at a rate in excess of 10000 MSCFD. This is the indication of high

productivity.

The pressure stabilized too quickly after shut-in. For accurate transient analysis on such a

highly productive well the flow rates prior to buildup should be much higher.

The Log-log and Semi-log plots are shown in Figs 21 and 22.

The results are shown in the Table-9.

Table-9

Pre Acid Stimulation Well Test

Post Acid Stimulation Well Test

Flow Capacity k x h (md, m) 85000 85000

Skin (Total) 960 52


42

Fig

ure

20

P

ress

ure

and

Gas

flo

w r

ates

vs.

tim

e

1672

1668

1664

1000

0

5000

0

5060

7080

9010

011

012

0


43

Fig

ure

21

L

og-L

og p

lot:

dm

(p)

and

dm

(p)´

[p

si2

/cp

] v

s. d

t [h

r]

1000

00.

010.

11

10

1E+

5

1E+

6


44

Fig

ure

22

S

emi-

Log

plo

t: m

(p)

[psi

2/cp

] v

s. S

uper

posi

tion

tim

e

2.12

2E+

8

2.11

8E+

8

2.11

4E+

8

2.11

0E+

8

2.10

6E+

8

-4-3

.6-3

.2-2

.8-2

.4-2

-1.6

-1.2

-0.8

-0.4


45

CONCLUSIONS AND RECOMMENDATIONS The Study has determined gas reserves in Haseeb Gas Field (inclusive of inert gases) as

under:

Reserve Classification

The SML pay zone in the Haseeb-1 well exhibit good reservoir properties. The study

confirms that the Haseeb Field contains viable gas reserves which merit gas production / sale

on a commercial basis. A Gas buyer has already agreed to buy the Haseeb gas inclusive of

inert gases.

Like most of the Carbonate Reservoirs, the SML in the Haseeb-1 well has reacted positively

to the acid treatment performed by Schlumberger. After the acid treatment it was reported

that the well had a flow capacity of 28.5 MMSCFD. Thus study highly recommends that this

production enhancing technique be applied to the next / subsequent appraisal / development

wells.

It is concluded that the gas production from these wells will increase by increasing tubing

size from 2.79 inches to 3.92 inches. The production potential is expected to increase to

28.5 MMSCFD.

Since an increase in gas flow rate was logged with an increase of choke size, the Study

recommends that an optimum higher size choke be selected to obtained safe and maximum

production from the well / wells. An optimal gas production rate from the well is indicated as

12 - 18 MMSCFD for an initial plateau of 10-15 years and a field flow rate with multiple

wells at around 30 - 35 MMSCFD.

Sui Main Limestone (SML) P-90 P-50 P-10

Total Gas BSCF 217 230 261

Recoverable Gas BSCF 174 177 196


46

To optimize reservoir performance, the Study recommends that during the production phase,

monitoring of reservoir behavior be undertaken for water production and other parameters.

The gas field is commercially viable and merits development for sale of gas. Nearby

infrastructure (gas buyer pipelines) and gas buyer's willingness to take gas to meet the acute

demand growth market, are added incentives for its development.

It is suggested that in order to safely recover the estimated recoverable reserves indicated in

this Study, the lower most interval of the pay may be carefully re-examined through logs for

potential water problems.

VOLUMETRIC RESERVE EVALUATION AND THIRD PARTY ... · Location map of Yasin Block (2768-7) in...

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