transglobe energy corporation competent person's report effective december

Effective December 31, 2017
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May 30, 2018 Project 1171464 Mr. Lloyd Herrick TransGlobe Energy Corporation Suite 2300, 250 - 5th Street SW Calgary, Alberta T2P 0R4 The Directors Canaccord Genuity Limited 88 Wood Street London, UK EC2V 7QR Dear Sir: Re: TransGlobe Energy Corporation Competent Person’s Report (CPR) Effective December 31, 2017 GLJ Petroleum Consultants (GLJ) has completed an independent reserves assessment and evaluation of the onshore Canadian oil and gas and Egyptian oil properties of TransGlobe Energy Corporation (the “Company”) and its subsidiaries (together the “Group”). This report has been prepared in preparation for the admission of the Company’s issued and to be issued share capital to the AIM market of the London Stock Exchange Plc. This CPR was prepared in compliance with the “AIM Note for Mining, Oil and Gas Companies, June 2009”, as published by the London Stock Exchange. The effective date of this evaluation is December 31, 2017. This evaluation has been prepared in accordance with reserves definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (COGEH), which replaced the standards published by the CIM known as National Policy 2B (CIM NP-2B) in June 2002. The results of this evaluation would be the same or immaterially different under the use of procedures and standards contained in the Petroleum Resources Management System (PRMS) of the Society of Petroleum Engineers (SPE). In preparation of this report, GLJ has received customary fees associated with the preparation of the reserves evaluation report. However, neither GLJ nor any of its directors, staff or sub-consultants who contributed to the report has any interest in the Company, its subsidiaries, or any of its assets or securities (including the common shares). Our fees are not linked to the admission of the shares to trading on the Exchange or the value of the Company. Additionally, GLJ confirms that we:
• are professionally qualified and members in good standing of the Association of Professional Engineers and Geoscientists of Alberta (APEGA);
4100, 400 – 3rd Ave SW Calgary, AB, Canada T2P 4H2 | tel 403-266-9500 | gljpc.com
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• have at least 5 years of experience directly relevant to the estimation, assessment and evaluation of oil and gas reserves and resources;
• are independent of the Company, its directors, senior management and advisers; • will receive a fee for the preparation of the report in accordance with normal professional consulting
practice. This fee is not contingent on the admission of the Company to AIM, or value of the Company and we will receive no other benefit;
• are not a sole practitioner; • have the relevant and appropriate qualifications, experience and technical knowledge to appraise
professionally and independently the oil and gas assets owned by the Company and its subsidiaries (together the “Group”);
• consider that the scope of the report is appropriate and includes and discloses all information required to be included therein and was prepared in accordance with the Guidance Note for Mining, Oil & Gas Companies issued by London Stock Exchange plc in June 2009.
It was GLJ’s primary mandate in this evaluation to provide an independent evaluation of the oil and gas reserves of the Company in aggregate. Accordingly, it may not be appropriate to extract individual property or entity estimates for other purposes. Our engagement letter notes these limitations on the use of this report. The reserves estimates included in this CPR are based on production information as provided by the Company, as of December 31, 2017. The Company provided GLJ with certain geological, geophysical, economic (including lease operating statements and capital cost estimates) and engineering information used in evaluating the Company’s assets. In the preparation of reserves estimates for the Company, a site visit was not deemed to be necessary; as such, no site visit was conducted by GLJ. The Company has confirmed that to their knowledge, no material change of circumstances or information would have a significant impact on the reserves contained herein has occurred between the effective date of the report and May 30, 2018. All values presented in this report are in United States dollars. It is trusted that this evaluation meets your current requirements. Should you have any questions regarding this analysis, please contact the undersigned. Yours very truly, GLJ PETROLEUM CONSULTANTS LTD.
Leonard L. Herchen, P. Eng. Vice President LLH/jem Attachments
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INDEPENDENT PETROLEUM CONSULTANTS’ CONSENT The undersigned firm of Independent Petroleum Consultants of Calgary, Alberta, Canada has prepared an independent evaluation of the TransGlobe Energy Corporation (the “Company”) oil and gas properties and hereby gives consent to the use of its name and to the said estimates. The effective date of the evaluation is December 31, 2017. In the course of the evaluation, the Company provided GLJ Petroleum Consultants Ltd. personnel with basic information which included land data, well information, geological information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product prices, operating cost data, capital budget forecasts, financial data and future operating plans. Other engineering, geological or economic data required to conduct the evaluation and upon which this report is based, were obtained from public records, other operators and from GLJ Petroleum Consultants Ltd. nonconfidential files. The Company has provided a representation letter confirming that all information provided to GLJ Petroleum Consultants Ltd. is correct and complete to the best of its knowledge. Procedures recommended in the Canadian Oil and Gas Evaluation (COGE) Handbook to verify certain interests and financial information were applied in this evaluation. In applying these procedures and tests, nothing came to GLJ Petroleum Consultants Ltd.’s attention that would suggest that information provided by the Company was not complete and accurate. GLJ Petroleum Consultants Ltd. reserves the right to review all calculations referred to or included in this report and to revise the estimates in light of erroneous data supplied or information existing but not made available which becomes known subsequent to the preparation of this report. The accuracy of any reserves and production estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserves and production estimates presented herein are considered reasonable, the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. Revenue projections presented in this report are based in part on forecasts of market prices, currency exchange rates, inflation, market demand and government policy which are subject to many uncertainties and may, in future, differ materially from the forecasts utilized herein. Present values of revenues documented in this report do not necessarily represent the fair market value of the reserves evaluated herein.
PERMIT TO PRACTICE GLJ PETROLEUM CONSULTANTS LTD.
Signature: Date: May 10, 2018
PERMIT NUMBER: P 2066 The Association of Professional Engineers and Geoscientists of Alberta
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INTRODUCTION 7
DISCUSSION Corporate Summary 9 Canadian Assets Geology 17 Performance Review, Reserves and Production Forecast 24 Egyptian Assets - Northwest Gharib Geology 30 Northwest Gharib Reserves and Development Forecast 33 West Bakr Geology 36 West Bakr Reserves and Development Forecast 38 West Gharib General Overview 42 West Gharib Geology 44 West Gharib Performance Review, Reserves and Development Forecast 48 Exploration Concessions General Overview 54
MAPS 59
SUMMARY 91
EVALUATION PROCEDURE 156
AFTER TAX ANALYSIS 166
APPENDIX II 198 Representation Letter
May 31, 2018 13:53:31
GLJ Petroleum Consultants (GLJ) was commissioned by TransGlobe Energy Corporation (the
“Company”) to prepare an independent evaluation of the oil and gas reserves of the Company and
its subsidiaries (together the “Group”) effective December 31, 2017. The locations of the most
significant reserves properties are indicated on the attached index maps.
The evaluation was initiated in November 2017 and completed by January 2018. Estimates of
reserves and projections of production were generally prepared using well information and
production data available from public sources to approximately September 30, 2017. The
Company provided land, accounting data and other technical information (including Egyptian
technical and production information) not available in the public domain to approximately October
31, 2017. In certain instances, the Company also provided recent engineering, geological and other
information up to December 1, 2017. The Company has confirmed that, to the best of its knowledge,
all information provided to GLJ is correct and complete as of the effective date.
This evaluation has been prepared in accordance with procedures and standards contained in the
Canadian Oil and Gas Evaluation (COGE) Handbook, which replaced the standards published by
the CIM known as National Policy 2B (CIM NP-2B) in June 2002. The reserves definitions used
in preparing this report (included herein under “Reserves Definitions”) are those contained in the
COGE Handbook and the Canadian Securities Administrators National Instrument 51-101 (NI 51-
101). The results of this evaluation would be the same or immaterially different under the use of
procedures and standards contained in the Petroleum Resources Management System (PRMS) of
the Society of Petroleum Engineers (SPE).
The evaluation was conducted on the basis of the GLJ January 1, 2018 Price Forecast which is
summarized in the Product Price and Market Forecasts section of this report.
Tables summarizing production, royalties, costs, revenue projections, reserves and present value
estimates for various reserves categories for individual properties and the Company total are provided
in the tabbed sections of this Summary Report.
The Evaluation Procedure section outlines general procedures used in preparing this evaluation. The
individual property reports, provided under separate cover, provide additional evaluation details. The
following summarizes evaluation matters that have been included/excluded in cash flow projections:
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• The effect on projected revenues of the any of the Group’s financial hedging activity have
not been included,
• Provisions for the abandonment and reclamation of all of the Group’s Canadian existing
and future wells to which reserves have been attributed have been included; all other
abandonment and reclamation costs have not been included,
• Provisions for the abandonment and reclamation of all the Company’s Egyptian existing
and future wells were not included pursuant to the terms of the Production Sharing
Contracts (PSCs) and the timing of lease expiry.
• General and administrative (G&A) costs and overhead recovery have not been included,
• Undeveloped land values have not been assessed in this evaluation.
Provisions for lease expiry were made for each development lease located in Egypt using the
following dates:
Lease Expiry
West Gharib West Gharib (Hana/ Hana West) Dec-24 Dec-29 Dec-34
West Gharib Hoshia Jun-30 Jun-35 Jun-40
West Gharib West Hoshia Oct-30 Oct-35 Oct-40
West Gharib Arta Oct-31 Oct-36 Oct-41
West Gharib East Arta Aug-32 Aug-37 Aug-42
West Bakr H Apr-25 Apr-30 Apr-35
West Bakr K (K and M) Apr-25 Apr-30 Apr-35
NWG Development Lease 1 Dec-36 Dec-36 Dec-36
NWG Development Leases 2, 3 and 4 Sep-37 Sep-37 Sep-37
Economic forecasts are provided on an after tax basis including tax pools provided by the Company
in the “After Tax Analysis” section.
The preparation of an evaluation requires the use of judgment in applying the standards and
definitions contained in the COGE Handbook. GLJ has applied those standards and definitions
based on its experience and knowledge of industry practice. While GLJ believes that the reserves
data set forth in this evaluation have, in all material respects, been determined and are in
accordance with the COGE Handbook, because the application of the standards and definitions
contained in the COGE Handbook require the use of judgment there is no assurance that the
applicable securities regulator(s) will not take a different view as to some of the determinations in
the evaluation.
CORPORATE SUMMARY
The Company engaged GLJ Petroleum Consultants (GLJ) to prepare an evaluation of the Group’s
Canadian and Egyptian oil and gas assets and to complete a Competent Person’s Report (CPR) for
their admission to the AIM market of the London Stock Exchange Plc. The Group’s assets include
two oil and gas fields located in southern Alberta, Canada and three concessions located in Egypt. The
Group’s exploration concessions located in Egypt were not evaluated for this CPR; however, a
summary of the assets has been included.
The Canadian assets include the Harmattan and Lone Pine Fields, which are approximately 80
kilometers north of Calgary, Alberta (Map 1). The Group holds various working interests in several
wells in these fields as detailed in their individual property reports. Oil and gas production is primarily
from the Upper Cretaceous Cardium Formation, with additional production from the Lower
Cretaceous Viking and Mannville, Mississippian Elkton and Devonian Wabamun Formations.
The Egyptian assets include three oil concessions located onshore immediately west of the Gulf of
Suez: Northwest Gharib, West Bakr and West Gharib. The concessions are located in the Eastern
Desert Region of Egypt, which is approximately 250 kilometers southeast of Cairo (Map 2).
The Northwest Gharib concession is comprised of 23 wells situated in four development leases. These
wells have penetrated the Eocene Thebes Formation and the Miocene Upper Nukhul Lower Nukhul
and Rudeis Formations; however, only the Lower Nukhul Formation has demonstrated reasonable
success to date. The formation is comprised of both sandstones and conglomerates, which produce
heavy oil with an oil density of 21.5 degrees API.
The West Bakr concession includes development from three individual fields: the H, K and M Fields.
The concession includes 85 existing wells targeting the mid-Miocene Rudeis Group, which includes
numerous sandstone members. Primarily, heavy oil production is obtained from the Asl, Rudeis and
Yusr Members.
The West Gharib concession is comprised of five development leases or properties, which themselves
have been subdivided based on individual pools: Arta/East Arta, Hana/West Hana and Hoshia. These
properties are producing heavy oil from a combination of the early-to-mid Miocene Nukhul, Rudeis
and Kareem Formations.
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The Group’s Egyptian assets also include three exploration concessions located in the Western Desert
region in Egypt (Map 3), which were not assessed for prospective resources in this evaluation. They
include: South Alamein, South Ghazalat and Northwest Sitra. The primary reservoirs of interest in
these concessions are the Jurassic Khatatba sandstones, Cenomanian Bahariya sandstone and the
Turonian-Cenomanian Abu Roash sandstones and carbonates.
GLJ has reviewed the production and development plans provided by the Group for their oil and gas
assets to assign reserves attributed to the proved producing, total proved, total proved plus probable
and total proved plus probable plus possible categories as of the effective date. Contingent and/or
prospective resources have not been estimated as part of this report. To evaluate contingent and/or
prospective resources, the Group would be required to collect and make available additional data to
GLJ. GLJ cannot currently give an indication as to the size or materiality of these resources. GLJ was
not engaged to and has not currently evaluated the contingent and/or prospective reserves attributable
to the Group’s assets. Our engagement agreement details the scope of the evaluation.
Reserves and Net Present Value (NPV)
A summary of the Group’s reserves and NPV are as illustrated in the following tables. The Group’s
NPV of the reserves is based on an analysis of future production forecasts, capital expenditures,
operating expenses, royalties or production sharing contract terms and product prices.
The reserves as presented above have not been further adjusted for risk and are consistent with the
reserves guidance outlined in the COGE Handbook. The reserves reflect the appropriate level certainty
as associated with proved, proved plus probable and proved plus probable plus possible reserves.
It should be noted that for the Egyptian oil assets, net attributable reserves are the Group’s net
entitlement of Cost Oil plus Profit Oil plus Tax Recovery, as it has been defined in each Production
Sharing Contract (PSC).
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Summary of Oil and Gas Reserves by Status TransGlobe Energy Corporation
Proved Proved & Probable
TransGlobe Energy
Natural Gas Liquids (Mbbl) 3,476 6,112 8,210 2,719 5,052 6,800
Total BOE (Mboe) 10,706 17,879 23,307 8,926 15,298 19,872
Lone Pine Alberta, Canada
TransGlobe Energy
Natural Gas Liquids (Mbbl) 67 117 260 51 83 217
Total BOE (Mboe) 716 1,377 2,455 648 1,232 2,211
Northwest Gharib, Egypt
TG NW Gharib Inc.
Total BOE (Mboe) 624 1,357 2,253 274 596 989
West Bakr, Egypt
TransGlobe West Bakr
Gas (MMcf) 0 0 0 0 0 0
Total BOE (Mboe) 7,799 13,413 17,823 3,727 6,408 8,186
West Gharib, Egypt
TransGlobe West Gharib
Total BOE (Mboe) 7,698 11,850 16,648 5,029 7,735 10,859
Total Assets
Total BOE (Mboe) 27,543 45,875 62,485 18,603 31,268 42,118
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Note: (1) In the above table, "Company Gross" means the Company's gross reserves, which are the Company's working
interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Company. "Net" means the Company's working interest (operating and non-operating) share after deduction of royalty obligations, plus the Company's royalty interest in production or reserves, before taxes.
(2) The definition of "Company Gross" in (1) above, which is the definition contained in National Instrument 51-101
and the COGE Handbook, differs from the definition of "Gross" contained in the AIM Note for Mining, Oil and Gas Companies, June 2009, which forms part of the AIM Rules for Companies (the "AIM Note"), each as published by the London Stock Exchange. The definition of "Gross" contained in the AIM Note is "100% working interest reserves and/or resources attributable to the license" while “Net attributable” are those attributable to the Company. If the definition of "Gross" contained in the AIM Note was applied to the reserves in the above table as at December 31, 2017, the Gross attributed to the licenses would be as set forth in the table below, which table has been provided for the sole purpose of compliance with the AIM Note.
(3) "Operator" is the name of the company that operates the asset. Although the operators for Northwest Gharib, West
Bakr, and West Gharib are as noted above, each of the operators has formed an incorporated joint venture company with the Egyptian General Petroleum Corporation, with each party holding a 50% interest in such company, the purpose of which is to carry out the exploitation operations for each concession. The joint venture companies for the Northwest Gharib, West Bakr, and West Gharib concessions are, respectively, North West Gharib Petroleum Company, West Bakr Petroleum Company and Dara Petroleum Co.
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Summary of Oil and Gas Reserves by Status (AIM Note) TransGlobe Energy Corporation
TransGlobe Energy
Total BOE (Mboe) 11,053 18,418 24,544 8,926 15,298 19,872
Lone Pine Alberta, Canada
TransGlobe Energy
Total BOE (Mboe) 716 1,377 2,455 648 1,232 2,211
Northwest Gharib, Egypt
TG NW Gharib Inc.
Total BOE (Mboe) 624 1,357 2,253 274 596 989
West Bakr, Egypt
TransGlobe West Bakr
Gas (MMcf) 0 0 0 0 0 0
Total BOE (Mboe) 7,856 13,496 17,933 3,727 6,408 8,186
West Gharib, Egypt
TransGlobe West Gharib
Total BOE (Mboe) 7,698 11,850 16,648 5,029 7,735 10,859
Total Assets
Total BOE (Mboe) 27,947 46,497 63,834 18,603 31,268 42,118
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Note: (1) In the above table, "Gross" means 100% working interest reserves and/or resources attributable to the license
while “Net attributable” are those attributable to the Company.
(2) "Operator" is the name of the company that operates the asset. Although the operators for Northwest Gharib, West Bakr, and West Gharib are as noted above, each of the operators has formed an incorporated joint venture company with the Egyptian General Petroleum Corporation, with each party holding a 50% interest in such company, the purpose of which is to carry out the exploitation operations for each concession. The joint venture companies for the Northwest Gharib, West Bakr, and West Gharib concessions are, respectively, North West Gharib Petroleum Company, West Bakr Petroleum Company and Dara Petroleum Co.
Summary Net Present Values of Future Net Revenue TransGlobe Energy Corporation
After Income Taxes Discounted At (%/year)
0% 5% 10% 15% 20%
Reserves Category M$ M$ M$ M$ M$
Proved
Developed Non-Producing 17,028 14,751 12,877 11,332 10,054
Undeveloped 94,594 59,860 40,059 27,816 19,741
Total Proved 353,594 278,236 230,022 196,951 172,992
Total Probable 233,627 148,296 105,628 81,029 65,298
Total Proved Plus Probable 587,221 426,532 335,650 277,980 238,290
Total Proved Plus Probable Plus Possible 791,921 548,043 420,326 342,691 290,639
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Summary of Oil and Gas Assets A summary of the working interest and current development status for the Group’s reserves properties
is provided in the following table.
Summary of Interests of TransGlobe Energy Corporation’s Oil and Gas Reserves Properties Effective December 31, 2017
Asset Lease Operator Working Interest* Status
Lease Expiry Date
Canada, Lone Pine
TransGlobe Energy Corporation
Egypt, Northwest Gharib
and Development
(plus extensions)
year extension periods as per the PSC.
Egypt, West Bakr
year extension periods as per the PSC.
Egypt, West Gharib
92.2 km2
Lease expiries vary by Development Lease and are subject to 5-year extension
periods as per the PSC.
Egypt, South Alamein
100% Exploration June 26, 2018 800.0 km2 Extension requested
Egypt, South Ghazalat
2018 1414.0 km2 Exploration Phase 2 expiry
Egypt, Northwest Sitra
TransGlobe Petroleum Egypt Inc.
100% Exploration July 7, 2018 1946.0 km2 Exploration Phase 1 expiry
* Average interest on participation
** Production is allocated 99.4% to the Company by virtue of a unitization agreement.
The Group’s interest in the Egyptian contracts are subject to the terms of their PSCs. Below is a
summary of terms included for each contract area.
Production Sharing Contract
Recovery (%)
Recovery (%) Northwest Gharib 25 15
West Bakr 30 15
West Gharib 30 29.6
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Income tax is paid at a statutory rate of 40.55 percent on behalf of the Group by the Egyptian
General Petroleum Corporation. Income taxes payable are recoverable costs for net oil attribution.
Details of these agreements are further discussed in the Economic Parameters section of this report,
under the heading “Interests Descriptions” of this report.
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CANADIAN ASSETS GEOLOGY
Within the Group’s Canadian assets located in Alberta, Canada (Map 4), the primary hydrocarbon
bearing interval is the Cretaceous aged Cardium Formation. Additional hydrocarbon bearing zones
include carbonates of the Mississippian-age Elkton Member and Devonian Wabamun Formation,
and sandstones of the Cretaceous age Ellerslie and Viking Formations (Figure 1). The Canadian
assets include the Harmattan and Lone Pine properties.
Cardium Formation
Background
The Group has targeted the Cardium Formation for oil production using horizontal well technology
within the Harmattan property.
The Cardium Formation was deposited within the western margin of the Cretaceous Western
Interior Seaway – approximately 90 million years ago, during the Late Cretaceous, late Turonian
to early Coniacian age. Deposition of the Cardium Formation was controlled by sea-level
fluctuations during an overall transgressive cycle; and is comprised of shoreface to offshore
deposits. It is bounded above and below by the shales of the Wapiabi and Blackstone Formations,
respectively. The Harmattan area consists of one coarsening upward transgressive sequence which
is part of the Raven River Member of the Cardium Formation. This Raven River Member is capped
by a regional erosional surface where conglomerates were periodically deposited. The rising
Cordillera, to the west, was the source rock for these marine deposits.
Target Reservoir Interval Description(s)
The Raven River Member is the main target for horizontal production. It consists of one,
approximately 20-metre-thick, coarsening upward sequence that was deposited within a lower
shoreface to inner shelf marine setting; and is overlain by laminated mudstones. It grades from
massive dark mudstone at the base, through bioturbated muddy siltstone to bioturbated sandstone
(which is termed the transition zone by GLJ), and finally into non-bioturbated sandstone above.
Occasionally, a transgressive lag conglomerate overlies the sands. GLJ subdivides the Cardium
sequence into three hydrocarbon bearing zones: the conglomerate, the sandstone, and the transition
zone. These conglomerates have not been developed within the Harmattan property but have been
included in the discussion for reference information.
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The conglomerate zone, where present, is the uppermost pay interval and can be clast or mud
supported. On logs it often appears clean but dense due to its variable siderite content. The
conglomerate zone has average petrophysical parameters, determined from special core analyses
(SCAL), of 6 percent total porosity, 10 percent water saturation (Sw), and permeabilities ranging in
the 100’s to 1,000’s of mD. The sandstone zone consists of interbedded very fine to medium grained
sands and shales. It is cleanest at the top with the shale content increasing down section to 30
percent. Logs and cores were used to determine the total porosity within the sandstone zone, which
ranges between 3.5 and 18 percent across the Cardium fairway, with an average of 4.6 percent in
the Harmattan area. A strong correlation is seen between the density curve, using the sandstone
scale, and porosity readings from core analysis. Within the sandstone zone the permeabilities range
from 0.5 to 10 mD. The transition zone is the lowermost pay interval. It is composed of bioturbated
silty, sandy, mudstone, with an increasing shale volume moving down section. The volume of shale
ranges from 30 percent at the top to 70 percent at the base. Here the total porosities range between
3.5 to 7 percent on average. The transition zone is the tightest of the three zones with permeabilities
of 0.1 to 0.5 mD. It is distinguishable from the sandstone zone due to the increasing gamma,
decreasing resistivity and increasing neutron-density separation that are attributed to the increased
shale content. Within the Harmattan property the transition zone is tight.
Pay Determination
A review of the client’s lands and surrounding acreage was done by examining all publicly available
vertical, modern, open-hole logs with an attempt to include at least one well per section. GLJ did
not have access to core photos, FMI logs, or seismic for this review.
The methodology for evaluating recoverable resource begins by subdividing the well, first into
coarsening upward cycles and then into the three zones. Each of these zones are evaluated
individually and then combined to yield the total hydrocarbon pour volume (HCPV) for the well.
Within the conglomerate zone, average parameters of 6 percent porosity and 10 percent Sw are
applied to the total thickness. Within the sandstone and transition zones, the pay is determined using
the regional shale baseline as the porosity cutoff. Within the Wapiabi and Blackstone shales that
encase the Cardium Formation there is little variability in the porosity readings. This average shale
porosity is identified as the shale baseline. The shale baseline is constant along strike but decreases
as you move down dip, due to compaction from increasing depth of burial. It represents the porosity
that is attributed to the non-reservoir portion of the rock, where the sand content is very low, and
the pores are filled with water. Porosity readings greater than the shale baseline are attributed to
increases in sand content and have the potential to store hydrocarbons. Once the regional shale
baseline is determined the porosity logs are then normalized to this value. For example, if the
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regional shale baseline is at 3 percent but the well log is reading 2 percent, then the porosity curves
must be shifted one porosity unit to the left. Within the Harmattan property, the shale baseline
porosity on the density log was observed to vary from 2 to 5 percent with an average shale baseline
porosity reading of 3 percent. Where possible, core was used to confirm the sandstone density log’s
readings. The density curve, when using a grain density of 2,650, closely matches the core porosity
and thus is used as the preferred method for determining total porosity within the sandstone and
transition zones.
The sandstone zone’s Sw is based on bulk volume water (BVW) relationships estimated from results
in low permeability samples of SCAL along with tritium doped mud core and invert mud core
samples. To calculate the Sw for the transition zone, its volume of shale (Vsh) and inversely the
volume of sand (Vss) need to be determined. This is done by comparing the separation between the
neutron and density curves within the transition zone to that of the shale below. The transition zone
Vsh is equal to the transition porosity separation divided by the shale porosity separation. The BVW
within the transition is the weighted average of the Vsh BVW and the Vss BVW. For the Vsh BVW,
the shale porosity is equal to the shale baseline, and the Sw is equal to 100 percent. For the Vss
BVW the sand porosity is calculated by subtracting the sum of the Vsh times the shale baseline
porosity from the transition zone normalized density log porosity; and then dividing by the Vss. The
Sw for the sand is then calculated using the calculated Vss porosity with the sandstone BVW.
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Figure 2: Type Log of the Cardium formation within the Harmattan area References: Bulletin of Canadian Petroleum Geology Vol. 31, (Dec 1983) Cardium Formation 3. Bulletin of Canadian Petroleum Geology Vol. 34, (June 1986) Cardium Formation 6. Bulletin of Canadian Petroleum Geology Vol. 17, (March 1969) Geology Crossfield East and Lone Pine Creek Gas Fields, Alberta.
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The Mississippian-aged Elkton reservoirs consist of subcropping, truncated, and partially eroded
Elkton Member carbonates of the Turner Valley Formation. The Turner Valley Formation consists of
shallowing upwards, stratified, bioclastic carbonates deposited on a broad, open water, shallow marine
shelf environment. The Elkton reservoir rock consists largely of dolomitized carbonate with
secondary intercrystalline, vuggy and fracture porosity. The Elkton reservoirs conformably overlie
dense lagoonal sediments of the Shunda Formation. A Jurassic or Cretaceous shale section
unconformably overlies the Elkton. These shales provide the upper and lateral seals to the Elkton
reservoirs.
Ellerslie
The Ellerslie Formation was deposited during the Lower Cretaceous and unconformably overlies
either the eroded Paleozoic surface or Jurassic sediments in the area. The Ellerslie consists of a
relatively thick sequence of shales, siltstones and thin lenticular sands deposited within an incised
valley system. Ellerslie production in the asset area is obtained from these thin sands.
Viking
The Viking Formation was deposited during the Lower Cretaceous period and is composed of
areally extensive interbedded shale, silt and fine-grained sandstones, with up to 20 metres gross
thickness of sandstone. The Viking Formation is underlain by the upper Albian Joli Fou Formation
and overlain by the marine shales of the base fishscales.
Wabamun
Within the Lone Pine Field, the Upper Devonian-aged Wabamun Group has been targeted for
production from the porous Crossfields Member located within the dense Stettler Formation. The
Stettler Formation consists of a low porosity and permeability, light to medium brown, light grey
and white anhydrite that is alternating with and grading into brown dolomite. Conversely, the
Crossfield Member consists of porous dolomitized stromatoporoids and algal bank deposits. The
algal bank deposits consist of light brown to light and medium grey dolomites, where the effective
porosity is found within interconnected, tabular and branching pores. The light brown to cream
coloured stromatoporoids are tabular to massive in size and are found within medium to dark-brown
microcrystalline dolomite, where the porosity occurs within pinpoint to large vugs within the pores
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of the stromatoporoids. Dead asphaltic oil to live golden brown oil is found within the various pores
of the Crossfield Member.
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Performance Review and Reserves
Historical drilling in the Harmattan property on interest land consisted of vertical wells completed
in various Mannville channels and wells completed in the Elkton and Viking Formations.
Beginning in 2010, development was dominated by multi-fractured horizontal drilling into the
Viking, Mannville and Cardium Formations. In 2010, five horizontal wells were drilled to produce
oil in the Viking Formation, two horizontal wells were drilled to access oil in the Cardium
Formation and two horizontal wells were drilled into the Mannville Formation. In 2011, an
additional three horizontal wells were drilled into the Viking Formation, one horizontal well was
drilled into the Cardium Formation and 11 horizontal wells were drilled into the Mannville
Formation. As the Viking results were varied, 2012 drilling was primarily focused on the Cardium
and Mannville Formations, with 18 and 11 wells drilled, respectively. Only one horizontal well was
drilled into the Viking Formation in 2012. From 2013 to 2014, the primary focus was on drilling
into the Cardium Formation with 19 wells, and only four wells drilled into the Mannville
Formation.
In the Viking Formation, the 06-20-031-02W5 well was drilled in May 2010 and completed with a
nine-stage propane fracture treatment with 25 tonnes of proppant per stage. The well came on
production in June 2010 at a peak production rate of 60 bopd and had decreased to 10 bopd by
January 2011. Production at the analysis date, September 30, 2017, was 3.3 bopd. Initial reservoir
pressure was calculated to be approximately 1,122 psia, which is lower than offsetting wells
indicating the possibility of depletion.
A second well in the Viking Formation was drilled at 01-20-030-03W5 in June 2010 and came on
production in July 2010. The well was completed with an eight-stage propane fracture treatment.
Peak production was 270 bopd in August 2010 and had decreased to approximately 100 bopd by
mid-2011. Production at September 30, 2017 was 33 bopd.
A third well was drilled in the Viking Formation at 08-17-031-02W5, near the poorer 06-20 well,
in August 2010. The well came on production in September 2010 at 60 bopd and has performed
similarly to the offset well. Two additional Viking horizontal wells were drilled in October 2010 at
08-16-031-03W5 and 16-11-029-02W5. The 08-16 well came on production December 16, 2010
at approximately 30 to 40 bopd but steadily climbed to 50 bopd over five years. Production at
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September 2017 was 33 bopd. The 16-11 well also came on production in December 2010,
producing primarily gas at an initial rate of 1.6 MMcfpd and some oil at 14 bopd. Production at
September 2017 was 140 Mcfpd and 2 bopd.
Three wells were drilled and completed in the Viking Formation in 2011. The 02/16-16-030-03W5
well was drilled and cased; no reserves were assigned. The 02/06-10-030-03W5/2 and 08-04-031-
03W5 wells were both brought on production and produced gas.
One Viking well was drilled in 2012, at 12-29-030-03W5, offsetting the best Viking well at 01-20.
The well came on production in April 2012 at a rate of 22 bopd compared to the initial rate of 270
bopd at the 01-20 well, demonstrating the high degree of variability in the Viking Formation.
Production at September 2017 had since increased to 35 bopd.
In the Mannville B Pool, the 07-15-031-02W5 horizontal well was drilled in August 2010 and came
on production in September 2010. Production from the well was a mixture of oil and gas, similar
to nearby vertical well 14-15-031-02W5. Peak production occurred in October 2010 at 114 bopd
and 670 Mcfpd but had declined to approximately 10 bopd and 80 Mcfpd when it was suspended
in March 2014. A second well in the Mannville B was drilled at 05-18-031-02W5 in November
2010 and came on production in December 2010. The well was completed with a 10-stage fracture
treatment with approximately 25 tonnes of proppant per stage for the first nine stages and 54 tonnes
of proppant for the last stage. Initial reservoir pressure was calculated to be 3612 psia, lower than
nearby vertical producing wells at 14-07-031-02W5 and 08-13-031-03W5, indicating possible
interference. Peak production was 7.0 MMcfpd with high liquid yields. The well produced flat at
that rate until March 2012 and has since declined to 190 Mcfpd at September 2017.
A further 11 horizontal wells were drilled into the Mannville B Pool in 2011, another 12 in 2012
and an additional four in 2013 through 2014. Peak rates varied between 0.2 and 6.5 MMcfpd. One
well at 08-23-031-02W5 is an oil well with peak production of approximately 100 bopd in
November 2011, declining to 3 bopd in September 2017.
Sections 07 and 18 of 031-02W5 and 12 and 13 of 031-03W5 encompass an area of higher original
pressure in the Mannville B Pool than the adjacent sections. Peak rates and productivity of the
Mannville B wells has proven to be higher in this area. To date there are three vertical wells (14-
07, 07-12 and 08-13) and six horizontal wells (05-18, 09-18, 04-12, 08-12, 13-13 and 15-13) that
have produced in this area. Pressure analysis and flowing material balance plots of these wells
indicate that the strong horizontal wells are in communication, likely through the sand layers that
correlate between the vertical wells from log analysis.
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In the Cardium Formation, the 08-06-031-02W5 well was drilled in July 2010 and came on
production in August 2010. The well was completed with a nine stage propane fracture treatment.
The initial oil rate was 78 bopd and has since declined to 6 bopd in September 2017.
A second Cardium horizontal well at 00/07-03-032-03W5 was drilled in October 2011, offsetting
other non-interest Cardium horizontal wells in the area. The well was completed with a 20 stage
slickwater fracture treatment with 20 tonnes of proppant per stage. Oil production began in
November 2011 and had a peak rate of approximately 400 bopd in December 2011, decreasing to
17 bopd in September 2017.
A further 18 horizontal wells were drilled and completed in the Cardium Formation in 2012 and
another 18 in 2013. Peak rates ranged from 30 to 400 bopd. All wells were completed with a
slickwater treatment with an average of approximately 19 stages and 20 tonnes of proppant per
stage. The average initial 30-day rate for these wells was approximately 135 bopd.
The Group has drilled and completed three horizontal wells in the Cardium Formation in August
2017 with production beginning in October 2017; 02/01-11-031-03W5/0, 02/15-14-031-03W5/0
and 03/16-14-031-03W5/0. The wells were completed with a higher number of stages at 40 stages
and 15 tonnes of proppant per stage, with the expectation that the wells would have higher initial
rates and recoverable reserves than the historical horizontal wells in the area. The average initial
day one rate of the three wells was approximately 200 bopd. One well, 02/01-11, did not get all
fracture stages completed, and therefore has a lower initial rate of 80 bopd, however is expected to
have a longer plateau production as the well cleans up over time.
Reserves for the majority of the vertical wells were evaluated using decline analysis. Reserves for
the horizontal wells were assigned with consideration to flow regime, production performance, and
volumetric analysis in the case of the Cardium wells.
Thirty future Cardium locations and eighteen locations targeting the Ellerslie Formation of the
Mannville Group were considered in the evaluation. In the Ellerslie Formation, six locations were
considered as proven and twelve locations were considered as probable. Gas reserves were assigned
based on performance of the offset wells. All proved Ellerslie locations were deemed to be
uneconomic. Of the twelve probable locations considered, two have been removed because they
were uneconomic.
Twenty-three proved and seven probable horizontal Cardium locations were assigned reserves
based on performance of the offset wells and volumetric analysis, with consideration of an expected
increase in reserves from the higher number of fracture stages in the new wells compared to the
historical wells. An expected increase in reserves of approximately 30 percent over the historical
wells was estimated based on a study of multi-fractured horizontal wells in the Ferrier area where
a higher number of fracture stages has already been occurring and has resulted in incremental oil
recovery.
Surface losses and liquid yields for Harmattan were estimated from historical lease operating
statements obtained from the Group and are summarized below.
Surface Loss 30%
Ethane Yield 50 bbl/MMcf raw
Propane Yield 32 bbl/MMcf raw
Butane Yield 15 bbl/MMcf raw
Condensate Yield 20 bbl/MMcf raw
In the Lone Pine property, gas production is obtained from one Ellerslie and five Wabamun wells.
Oil production is obtained from four Ellerslie wells, which were producing a combined 40 bopd at
the effective date of this report. Producing reserves have been assigned by decline analysis on the
historical production trends.
Developed non-producing reserves have been assigned for a recompletion of the Ellerslie
Formation in the 01/05-18-031-27W4/0 well. Reserves have been assigned by analogy to offsetting
vertical production and the 05-18 recompletion has been scheduled to occur in 2020. Additionally,
undeveloped reserves have been assigned to three proved and three probable horizontal drilling
locations targeting the Ellerslie Formation. Undeveloped reserves have been assigned based on
performance of offset wells, with a volumetric check on overall recovery factor. Development of
the Ellerslie horizontal oil locations has been scheduled to occur between 2022 and 2024.
Surface losses and liquid yields for Lone Pine were estimated from historical lease operating
statements obtained from the Group and are summarized below.
Surface Loss 20%
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Production and Development Forecast
The producing oil and gas wells were forecast to decline from their current rate to the economic
limit using varying exponents.
Initial rates for non-producing wells were estimated from analogous wells with consideration to
differing completion strategies to be used in the future wells compared to the historical wells.
Horizontal well rates are initially expected to decline steeply due to the hydraulic fracturing of the
low permeability zones prior to decreasing at a shallower rate to the economic limit. Undeveloped
horizontal wells to be completed in the Cardium Formation are forecast to decline from the initial
rate using super-harmonic exponents of 1.3 and 1.5 in the proved and proved plus probable cases,
respectively, prior to reaching the terminal decline of 10 and 8 percent, respectively, where the oil
rate declines exponentially to the economic limit. Undeveloped horizontal gas wells in the Ellerslie
Formation are forecast to decline from the initial rate using super-harmonic exponents of 1.4 and
1.6 in the proved and proved plus probable cases, respectively, prior to reaching the terminal decline
of 10 and 8 percent, respectively, where the gas rate declines exponentially to the economic limit.
Undeveloped Ellerslie horizontal oil wells were forecast with a two-segment decline forecast based
on production of offsetting wells. Production was forecast to decline from the initial rate using
exponents of 0.6 and 0.7 in the proved and proved plus probable cases, respectively. When the
production rate reaches 40 bopd, production is then forecast with reduced exponents of 0.2 and 0.3
in the proved and proved plus probable cases, respectively, to the final economic limit.
New wells are to be drilled, completed and tied-in between 2018 and 2024. A complete
development schedule is presented in the individual property reports.
Economic Analysis The Group provided GLJ with their development plan, capital budget and lease operating statements
for the evaluation of their Canadian assets. Operating costs were based on January through September
2017 least operating statements as provided by the Group. The following operating cost assumptions
were utilized for the Harmattan property, presented in 2018 Canadian Dollars:
Fixed Well Cost $2,600 per well-month
Variable Oil Cost $4.00 per bbl
Variable Gas Cost $1.15 per Mcf (sales)
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The following operating cost assumptions were utilized for the Lone Pine property, presented in 2018
Canadian Dollars:
Variable Gas Cost $1.30 per Mcf (sales)
Capital costs assumptions for future horizontal development are presented below in 2018 Canadian
Dollars:
Ellerslie $1,500,000 $1,200,000 $500,000 $3,200,000
Cardium $1,000,000 $1,000,000 $500,000 $2,500,000
Abandonment and reclamation have been included for reserves wells, assuming a cost of $73,000
(2018 Dollars). The economic evaluation does not address non-reserves well abandonment, wellsite
reclamation, facility abandonment/salvage or possible environmental concerns.
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EGYPTIAN ASSETS NORTHWEST GHARIB GEOLOGY
GLJ has reviewed a number of Early to Middle Miocene stratigraphic zones across the West Gharib
Concession and NWG development leases, primarily in the Arta, East Arta, Hana, Hana West and
Hoshia Fields. All of these fields are located approximately 8 to 15 kilometers inland of the western
edge of the Gulf of Suez in Egypt.
Figure 3 - Generalized stratigraphic succession for the Gulf of Suez, Egypt (El Nady, Mohamed & S. Mohamed, Naglaa, 2016)
Production in these fields is primarily from the syn-rift sediments of the Nukhul, Rudeis and
Kareem Formations. Deposition of these syn-rift sediments was strongly controlled by the half-
graben structures that formed during the Oligocene-Miocene extensional event. A generalized
stratigraphic succession for the evaluated areas is presented above in Figure 3. Oil produced from
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these zones ranges 16 to 26 degrees API. Some production from the pre-rift Eocene-aged Thebes
Formation occurs across these properties, however, the producing wells have been evaluated by
decline only and no geologic assessment was conducted for any pre-rift formations.
Static Petrel models, hydrocarbon pore volume mapping, digital wireline log data, directional
surveys, final drilling reports and core analysis were provided to GLJ for this analysis. In each field,
a petrophysical assessment was conducted on a subset of wells and the output volumetric results
were compared to the results from the provided mapping and static models. Low, best and high
estimate volumetric cases were established in those fields where a greater degree of uncertainty in
total petroleum initially-in-place (PIIP) existed. A similar petrophysical methodology was used in
each field. Porosity was determined from neutron-density crossplots where log quality permitted.
Water saturations were calculated using a Simandoux water saturation equation, with water zones
or water analyses used to estimate Rw on a zone-by-zone basis. Where electrical properties had
been measured on particular rock types, these values were used for the m and n exponents in the
saturation equation. Tortuosity constant, a, was held constant at 1.
Northwest Gharib (NWG)
NWG consists of four development leases presented on Map 6. The NWG Development Lease 2 is
a northern extension of the Arta Main Red Beds Pool. The NWG Development Lease 3 is a southern
extension of the Arta Upper Nukhul Pools.
Porosity in the Arta area Lower Nukhul sands is typically in excess of 30 percent with
corresponding high permeabilities in the thousands of millidarcies. Two conglomeratic rock types
have also been identified, with differing characteristics. The first, a high permeability conglomerate
is matrix-supported, with the matrix sands exhibiting similar permeabilities to the clean sandstone
rock type. However, porosity is lower in this unit as the conglomerate clasts reduce the overall
storage capacity. It is expected this rock type will behave similarly to the clean sandstone rock type,
with potentially some minor reduction in flow rate due to minor baffling effects of the conglomerate
clast material. Permeability measurements taken within the matrix sand of the conglomerate rock
type show it to be of comparable quality to the clean sandstones.
The second conglomerate rock type is described as a limey conglomerate, with overall lower
permeability due to cementation. Core analysis of this unit shows porosities in the range of 8 to 15
percent and permeabilities of 1 to 5 millidarcies. In the NWG area, these two conglomeratic rock
types have been encountered more commonly with thinner sand accumulations than found in the
Arta Main Pool. The calcareous Upper Nukhul Formation found in NWG Development Lease 3 is
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described as moderate porosity limestones, typically 12 to 19 percent, with low permeabilities,
typically less than 1 millidarcy.
NWG Development Leases 1 and 4 are to the north of the East Arta Concession and are targeting
the Lower Nukhul Formation. The Lower Nukhul in this area has been mapped in separate fault
blocks, however, there is some uncertainty in the fault positioning in this area. Due to mixed results
in wells targeting the Lower Nukhul zone over these leases, areas for reserves assignments have
been limited to near the existing wells with positive tests.
Fifteen wells were petrophysically evaluated in and around these four developments leases.
Hydrocarbon volume estimates were made on a well-by-well basis using outputs from the
petrophysical analysis and estimates of drainage area around each well.
References El Nady, Mohamed & S. Mohamed, Naglaa. (2016). Source rock evaluation for hydrocarbon generation in Halal oilfield, southern Gulf of Suez, Egypt. Egyptian Journal of Petroleum. 25. 383-389.
Page: 32 of 199
NORTHWEST GHARIB RESERVES AND DEVELOPMENT FORECAST
Heavy oil production comes from the Lower Nukhul Formation. To date, 23 wells have been drilled
in the Upper and Lower Nukhul, Thebes, and Rudeis Formations with limited success. Nonetheless,
the most recent Lower Nukhul wells show improved results. As of the effective date, December 31,
2017, producing reserves were assigned to three wells and non-producing reserves were assigned
to another three wells pending completion. No reserves were assigned to the Thebes or Rudeis
Formations.
The Lower Nukhul Formation is comprised of both sandstones and conglomerates. The Group has
obtained good results from this formation by drilling wells NWG-03X and NWG-38AX in late
2016. Both of these wells have shown promising results. Oil density from the Lower Nukhul at
these wells is 21.5 degrees API.
Producing and undeveloped reserves have been assigned in the Upper and Lower Nukhul
Formations. All reserves were assigned volumetrically. Proved, probable and possible producing
reserves were assigned to the NWG-01X, NWG-03X, NWG-05BX, NWG-16X, NWG-38AX, and
NWG38A-1 wells.
The NWG-03X well was drilled in Q3 2016 and has shown promising results. The well was
assigned recovery factors of 8.5, 10 and 12.5 percent for the total proved, total proved plus probable
and total proved plus probable plus possible cases, respectively, with an oil initially-in-place (OIIP)
of 3,294 Mbbls and a drainage area of 80 acres. As of the effective date, the well was producing at
a rate of 690 bbl/d and a water cut of 40 percent.
The NWG-01X well came on production in September 2017 and was assigned proved producing
reserves. The well was assigned recovery factors of 7, 10, and 13 percent for the proved, proved
plus probable and proved plus probable plus possible cases respectively, with an OIIP of 619
Mbbls. Additionally, the standing well NWG-01A was assigned probable undeveloped reserves.
The NWG-05BX well came on production in September 2017 and was assigned proved producing
reserves. The well was assigned recovery factors of 7, 10, and 13 percent for the proved, proved
plus probable and proved plus probable plus possible cases respectively, with an OIIP of 2,540
Mbbls. Additionally, the standing well NWG-05X was assigned proved undeveloped reserves, and
two additional probable and possible locations, NWG-05A and NWG-05C, were considered.
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The NWG-16X well was drilled in Q4 2016 and was recently completed and put on production.
The well was assigned recovery factors of 7, 10 and 13 percent, respectively, with an OIIP of 562
Mbbls and a drainage area of 80 acres.
The NWG 38 wells were analyzed on a pool basis. The NWG-38AX well was drilled in 2016 and
came on production in January of 2017 with very good results. Subsequently, wells NWG-38A1
and NWG-38A2 were drilled. NWG-38A1 has been assigned proved producing reserves while the
NWG-38A2 has not been assigned reserves due to testing water. Additionally, the Group has
indicated that the NWG-38A2 well will likely be transformed into an injector to support future
production from the rest of the pool. The reserves assigned to the pool were 318, 499, and 675
Mbbls for the total proved, total proved plus probable, and total proved plus probable plus possible
cases, respectively. A probable undeveloped location was also assigned. This well will be located
up-dip from the existing producers and is scheduled to come onstream in July 2019.
The Group provided geological mapping and petrophysical parameters for the Northwest Gharib
concession, which were reviewed and accepted for this evaluation. Recovery factors were assigned
based on performance of producing wells and future development that was considered for reserves.
A detailed summary of volumetric parameters and OIIP for each well assigned reserves is presented
below:
NWG-01A Redbed 80 12 10.8 47.9 1.08 388
NWG-03X Redbed 80 42.5 20.5 33.0 1.08 3,355
NWG-16X Redbed 80 18 11.1 51.1 1.08 561
NWG-38AX Redbed 160 31.9 13.1 37.5 1.08 3,002
NWG-A1 Redbed 60 30.5 9.9 48.3 1.08 673
NWG-38C Redbed 60 31.2 11.5 42.9 1.08 883
NWG-05BX Nukhul 80 58 13.3 42.7 1.08 2,540
NWG-05X Nukhul 80 60 14.9 40.4 1.08 3,062
NWG-05A Nukhul 80 59 14.1 41.6 1.08 2,794
NWG-05C Nukhul 80 59 14.1 41.6 1.08 2,794
A detailed summary of production rates, reserves and present values for all wells is included in the
individual property report.
Economic Analysis Operating costs were determined using the lease operating statements provided by the Group. The
timing and capital for the development of the reserves were based on 2018 budget information
provided by the Group. The following operating cost assumptions were utilized, presented in 2018
United States Dollars:
Capital costs assumptions for future development drilling are presented below in 2018 United
States Dollars:
Drill $950,000
Complete $150,000
Total $1,100,000
Well abandonment and reclamation costs were not included for any wells in this contract as the
Group is not subject to any abandonment liabilities.
The Group’s interest in this contract is subject to the terms of a PSC. A maximum of 25 percent of
revenue is used for cost recovery. The Group’s share of profit after cost recovery is 15 percent. The
Group is not entitled to any excess cost revenue, which is the difference between actual costs
incurred and the 25 percent maximum. Income tax is paid at a statutory rate of 40.55 percent on
behalf of the Group by the Egyptian General Petroleum Corporation. Cost pools have been included
in the fiscal regime and were based on the Cost Recovery Statements provided by the Group. An
oil surface loss of 0.944 percent has also been applied to this block as provided by the Group. The
contract is subject to a termination date of December 2036 (Development Lease 1) and September
2037 (Development Lease 2,3,4) for all reserves categories as provided by the Group. The
consolidated property cash flow projections for each of the reserves categories in this contract are
presented in the Economic Forecasts section of the individual property report.
The Northwest Gharib PSC is subject to a lease expiry, currently December 2036, that includes 5-year
extension periods within the agreement. Since production forecasts do not extend beyond the current
lease expiry, no lease extensions have been assumed.
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(1) Dolson, J.C, M. V. Shann, H. Hammouda, R. Rashed, S. Matbouly, 2000, The Petroleum Potential of Egypt Presented in the
Second Wallace E. Pratt memorial Conference on Petroleum Provinces of the 21st Century, San Diego, California.
WEST BAKR GEOLOGY
West Bakr is in the Eastern Desert Region of Egypt, approximately 250 kilometers southeast of
Cairo. The Eastern Desert region is part of the Gulf of Suez Petroleum system which is a major
Miocence syn-rift system formed by early Oligocene opening of the Gulf of Suez. Most wells in
this area are located along the crest of tilted fault blocks and four-way closures charged from
numerous flanking basins (J.C. Dolson et al., 2000)1. The tilted fault blocks caused by the syn-rift
tectonics also controlled syn-rift deposition of sediments. Therefore, in the Miocene section there
is a complex interplay between syn-rift structure and syn-depositional of reservoir facies. The area
of interest includes three oil fields; the H, K and M Fields (Map 7). The reservoirs are the numerous
sandstones of the early to mid-Miocene Rudeis Group, these include the Asl and Yusr sandstones.
The sandstones are relatively clean with good porosities, generally 20 to 24 percent. There have
been close to 100 wells drilled in this area and as many of the successful wells have been producing
for a significant amount of time, reserves have primarily been calculated using decline analysis on
existing production performance. However, there are two areas in this region where volumetric
analysis was used to help constrain possible reserves as a result of future development. The southern
portion of the H Field which is under pressure support from water injection into down dip wells
and the southern portion of the K Field where there are planned infill drilling locations.
For the southern part of the H Field, six wells were selected to conduct petrophysical analysis on
to verify the hydrocarbon pore volume maps provided by the Group. The wells analyzed were H-
10, H-11, H-12, H-18, H-10 and H-24. The resulting analyses were consistent with the provided
HCPV maps. Therefore, the in-place hydrocarbon volumes calculated from these maps could be
incorporated into the engineering reserves analysis of this area.
For the southern portion of the K Field, where significant infill drilling has been planned, the
provided Petrel geological model was examined. Wells K47, K48 and K-51 were selected to
conduct petrophysical analysis on in order to verify the geological model. These three wells are the
most recent wells drilled into this area and indicate that the oil-water contact (OWC) has moved up
from -3,666 metres relative to sea level to -3,622 metres relative to sea level due to ongoing
production. Even though there may be significant gas saturation in the transition zone
(between -3,666 and -3,622 metres) the higher level was taken as the OWC and no reserves were
assigned to the transition zone. The provided Petrel structural geological model was also examined
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and was found to be consistent with the log data. For the petrophysical analysis the HCPV
calculated by GLJ was approximately 82 percent of that presented by the Group. The major
difference is in the average net to gross pay ratio calculated by GLJ which is slightly lower and the
average SW calculated is slightly higher. However, due to the relatively sparse drilling, average
petrophysical parameters were applied to a gross rock volume of the whole structure rather than
map in detail the individual petrophysical properties across the structure. Therefore, there is
uncertainty in the range of possible in-place hydrocarbon volumes and this has been considered
when undertaking the engineering analysis of the wells.
Hydrocarbon pore volume mapping, as provided by the Group, is presented on Maps 8 through 21.
Page: 37 of 199
WEST BAKR RESERVES AND DEVELOPMENT FORECAST
The Group, under the PSC, holds a 100 percent interest in the West Bakr Block area of the West
Gharib Concession in Egypt, as shown on Map 7, except for select wells in the Yusr Block in the
West Bakr H Field. Wells H-10, H-11, H-12, H-13, H-14, H-16 and H-INJ-1 have a working
interest of 90 percent. The average working interest for the Yusr Block was estimated using recent
production rates for the current producers. Using this weighting method, the Yusr A Pool and the
Yusr B Pool working interests were estimated at 90.60 and 100 percent, respectively.
West Bakr is in the Eastern Desert Region of Egypt, approximately 250 kilometers southeast of
Cairo. The West Bakr Block has undergone extensive development and has been split into the H,
K and M Fields. The reservoirs are the numerous sandstones of the early to mid-Miocene Rudeis
Group, these include the Asl and Yusr sandstones. There have been over 100 wells drilled in this
area and as many of the successful wells have been producing for a significant amount of time.
Reserves have primarily been calculated using decline analysis on wells with sufficient production
history to indicate a trend; otherwise volumetric or analogy were used to estimate the ultimate
recovery. There are two areas in this region where volumetric analysis was used to help constrain
reserves; the southern portion of the H Field which is under pressure support from water injection
into down dip wells, and the southern portion of the K Field.
As of the October 31, 2017, there were 37 oil wells producing at a combined gross lease rate of
5,128 bopd with a cumulative production of 63.1 MMstb. In general, this report was prepared using
public production data and other information available as of the evaluation effective date.
The West Bakr Block has extensive existing development split between the H, K, and M Fields.
Decline analysis was used for wells with sufficient production history to indicate a trend; otherwise
volumetric or analogy were used to estimate the ultimate recovery. Gas is not conserved in the West
Bakr Block.
H Field
The H Field has been developed targeting the Asl, Bakr, Safra and Yusr sands. The field currently
has 13 oil wells producing at a combined gross lease rate of approximately 1,400 bopd as of October
31, 2017. Water cut for the H Field has fluctuated around 70 to 75 percent for the first ten months
of 2017.
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The Group has incorporated a waterflood pressure maintenance scheme in the southern portion of
the H Field for recovering additional oil from the un-swept zone in the Yusr A and B sands.
Probable undeveloped reserves were assigned to two wells (H-20 and H-27) to exploit the Yusr A
sand once the current producing sand is depleted. Proved non-producing reserves were assigned to
H-27 which is scheduled for a workover to isolate the upper perforations due to high observed water
cut. Proved non-producing reserves were assigned to H-09 for a workover to install a chemical
injection pump. Proved non-producing reserves were assigned to H-12 and H-18 to recomplete the
Yusr A and B sands. Reserves were assigned based on analogy to other wells producing from the
same formation.
GLJ has identified three undeveloped drilling locations within the H Field; one proved undeveloped
location, one probable undeveloped location, and one possible undeveloped location. Reserves
were assigned based on analogy to offsetting wells.
K Field
The K Field has been developed targeting the Asl and Rudeis sands. The field currently has 15 oil
wells producing at a combined gross lease rate of approximately 2,410 bopd as of October 31, 2017.
Water cut for the K Field has fluctuated around 65 to 70 percent for the first ten months of 2017.
Well K-28 was re-completed the Asl A1 sand in late 2016 with positive results, uplifting the
productivity of the well from approximately 40 to 110 bopd. Well K-25 was recompleted in 2017,
uplifting the productivity of the well from approximately 80 to 300 bopd. Three additional wells
have been identified for re-completion of the Asl sands; K-26, K-32 and K-34. Proved non-
producing reserves were assigned to the three wells based on decline analysis, or volumetric
calculations and analogy to offsetting wells producing from the same sands.
Wells K-48 and K-51 were drilled and completed in 2016 and commenced production in June 2016
and September 2016, respectively. Well K-47 was drilled and completed in 2017 and commenced
production in May 2017. These three wells encountered the Asl A1, A2, and A3 sands, however as
of the effective date, K-51 is the only well completed across the sands while the remaining wells
are only producing from the Asl A1 sand. Proved producing reserves were assigned based on
decline analysis and analogy to offsetting wells. Incremental proved non-producing reserves have
been assigned to K-47 and K-48 to commingle Asl A1 to A3 sands. Reserves were assigned based
on analogy to offsetting wells.
Page: 39 of 199
Proved non-producing reserves were assigned to K-27-A-ST1 for workover operations and re-
perforating the Asl A sand. Proved non-producing reserves were assigned to EPK-06X/2 for re-
completing the Asl lower sand. Possible non-producing reserves were assigned to EPK-02-X for
workover operations. Reserves were assigned based on decline analysis and analogy to offsetting
wells.
GLJ has considered seven proposed infill wells to effectively drain the K Field. Proved
undeveloped reserves were assigned to three wells (K-45, K-55 and K-56), while probable
undeveloped reserves were assigned to the remaining four wells (K-31, K-46, K-52 and K-54).
Reserves were assigned based on analogy to offsetting wells. The K-45 and K-46 wells have been
drilled since the effective date of this report.
M Field
The M Field has been developed targeting the Asl and Rudeis sands. The field currently has nine
oil wells producing at a combined gross lease rate of approximately 1,310 bopd as of October 31,
2017. Water cut for the M Field has fluctuated around 70 to 75 percent for the first ten months of
2017.
Well M-22/4 was re-completed in the ASL A sand in 2016 with initial rates above 700 bopd. Two
additional wells have been identified as re-completion candidates in 2018; Well M-16 is scheduled
to re-complete the Asl D sand, and well M-19 is scheduled to re-complete the Asl A and Asl C
sands. Probable non-producing reserves were assigned to the re-completions based on analogy to
offsetting wells producing from the same sands.
Economic Analysis Operating costs were determined using the lease operating statements provided by the Group. The
timing and capital for the development of the reserves were based on 2018 budget information
provided by the Group. The following operating cost assumptions were utilized, presented in 2018
United States Dollars:
Completion costs for existing wells were based on the Group’s budgeted capital, which varied by
well. Capital costs assumptions for future development drilling are presented below in 2018 United
States Dollars.
Drill $725,000
Complete $125,000
Total $850,000
Well abandonment and reclamation costs were not included for any wells in this contract as the
Group is not subject to any abandonment liabilities.
The Group’s interest in this contract is subject to the terms of a PSC. A maximum of 30 percent of
revenue is used for cost recovery. The Group’s share of profit after cost recovery is 15 percent. The
Group is not entitled to any excess cost revenue, which is the difference between actual costs
incurred and the 30 percent maximum. Income tax is paid at a statutory rate of 40.55 percent on
behalf of the Group by the Egyptian General Petroleum Corporation. Cost pools have been included
in the fiscal regime and were based on the Cost Recovery Statements provided by the Group. The
contract is subject to a termination date of April 2025, April 2030 and April 2035 for the proved,
probable and possible reserve categories, respectively. The consolidated property cash flow
projections for each of the reserves categories in this contract are presented in the Economic
Forecasts section of the individual property report.
The West Bakr PSC is subject to a lease expiry, which is currently April 2020. Provisions in the PSC
include 5-year extension periods within the agreement that are generally granted on request by the
parties of the PSC. It has been assumed that lease extensions will be sanctioned beyond the current
production lease expiry based on planned future development and robust economics of the
development leases. Provisions for lease expiry were made for each development lease using the
following dates:
Lease Expiry
West Bakr H, K and M Fields Apr-25 Apr-30 Apr-35
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WEST GHARIB GENERAL OVERVIEW
The Group, under the PSC, holds a 100 percent interest in three properties located in the West
Gharib Concession in Egypt immediately west of the Gulf of Suez. These properties include Arta
and East Arta, Hana and Hana West and Hoshia Fields. The West Gharab Concession is presented
on Map 22.
Arta and East Arta
Oil production is mainly from the Upper and Lower Nukhul Formations, with minor production
from the Thebes Formation. As of the October 31, 2017 analysis date, producing reserves were
assigned to 37 wells. The Arta property straddles the Arta and East Arta leases. The Arta lease has
been subdivided into the following sub-areas: Main Arta (further separated into production
formations), North Arta, South Arta and West Arta. The East Arta lease has been subdivided into
the East Arta and East Arta North sub-areas. The Arta and East Arta leases are presented on Map
23. As of the analysis date, the Arta property was producing at 3,794 bopd with cumulative
production of 17,125 Mbbl. All gas production in Arta is currently being utilized by the production
facilities and is therefore not reported.
The primary reservoir target across the Arta property is the Lower Nukhul Formation, found
primarily in the Main Arta sub-area. This Lower Nukhul Formation is comprised of both friable
sandstones and conglomerates and are referred to as the Red Beds. The Red Beds oil pool was
discovered in November 2010 with the successful drilling of the East Arta-07 well. As of the
analysis date, an additional 17 oil wells have been drilled in the Red Beds with a cumulative
production of 11,838 Mbbl. Oil density from the Red Beds is 18.4 degrees API.
Pressure declined quickly in the Red Beds at the onset of production which resulted in a preliminary
simulation model being constructed to evaluate the effects of pressure maintenance. Subsequently,
in July 2011, the Group initiated water injection into the Red Beds zone. In 2016, a dynamic
simulation model was constructed by an independent simulation consulting group to further
evaluate injection and optimize the recovery scheme. Currently, there are two active water injectors.
Developed non-producing reserves have been assigned to eight wells in the Arta property. These
wells have been scheduled to commence production in 2018 and 2019. Additionally, two
development locations have been assigned in the Arta property and will be drilled and on
production in 2018.
Page: 42 of 199
Hana and Hana West
Oil production is primarily from the Markha Member of the Kareem Formation, with additional
production from the Asl Member and the Lower Rudeis B. The Hana Field has undergone extensive
development and as of the effective date, there are producing reserves assigned to 16 wells. As of
the analysis date, the Hana Field was producing at 895 bopd and had a cumulative production of
14,040 Mbbl.
The primary reservoir in the Hana Field is the Markha Member, which has been under pressure
maintenance with the implementation of a waterflood in 2008. The Markha sands are bounded by
faults to the north, south and east, while the downdip eastern edge is limited by a water contact.
Reserves have been assigned to all currently producing wells as well as to numerous recompletion
candidates.
The Hana West Field is currently producing from the Asl and Lower Rudeis B sands of the Rudeis
Formation. The Lower Rudeis B is bounded by faults to both the east and west. The Asl-B3 sand
has been under pressure maintenance with the conversion of Hana West-03 to a water injector in
2009.
Two wells are currently producing from the Lower Rudeis B in Hana West, Hana West-09 and
Hana West-10. No additional development of the Lower Rudeis B is currently planned.
Hoshia
Oil production is primarily from the Rudeis Formation with minor production from the Nukhul
Formation. As of the effective date, the Hoshia property was producing at 400 bopd and had a
cumulative production of 4,086 Mbbl.
The Rudeis Formation has undergone water injection since September 2008 for pressure support.
As of the effective date, reserves have been assigned to five producing wells within the Rudeis Pool
and to additional injection, recompletions and an infill drilling location.
Two wells were assigned producing reserves in the Nukhul Formation, Hoshia-08 and Hoshia-10.
The latter is scheduled to be recompleted in the Rudeis Formation upon reaching economic cutoff.
No additional development is planned for the Nukhul Formation.
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WEST GHARIB GEOLOGY
GLJ has reviewed a number of Early to Middle Miocene stratigraphic zones across the West Gharib
Concession and North West Gharib development leases, primarily in the Arta, East Arta, Hana,
Hana West and Hoshia Fields. All of these fields are located approximately 8 to 15 kilometers
inland of the western edge of the Gulf of Suez in Egypt.
Figure 4 - Generalized stratigraphic succession for the Gulf of Suez, Egypt (El Nady, Mohamed & S. Mohamed, Naglaa, 2016)
Production in these fields is primarily from the syn-rift sediments of the Nukhul, Rudeis and
Kareem Formations. Deposition of these syn-rift sediments was strongly controlled by the half-
graben structures that formed during the Oligocene-Miocene extensional event. A generalized
stratigraphic succession for the evaluated areas is presented above in Figure 4. Oil produced from
these zones ranges 16 to 26 degrees API. Some production from the pre-rift Eocene-aged Thebes
Page: 44 of 199
Formation occurs across these properties, however, the producing wells have been evaluated by
decline only and no geologic assessment was conducted for any pre-rift formations.
Static Petrel models, hydrocarbon pore volume mapping, digital wireline log data, directional
surveys, final drilling reports and core analysis were provided to GLJ for this analysis. Relevant
maps, provided by the Group, are presented on Maps 24 to 30.
In each field, a petrophysical assessment was conducted on a subset of wells and the output
volumetric results were compared to the results from the provided mapping and static models. Low,
best and high estimate volumetric cases were established in those fields where a greater degree of
uncertainty in total PIIP existed. A similar petrophysical methodology was used in each field.
Porosity was determined from neutron-density crossplots where log quality permitted. Water
saturations were calculated using a Simandoux water saturation equation, with water zones or water
analyses used to estimate the water resistivity (Rw) on a zone-by-zone basis. Where electrical
properties had been measured on particular rock types, these values were used for the m and n
exponents in the saturation equation. Tortuosity constant, a, was held constant at 1. Arta and East Arta
The Arta lease is largely producing from the Lower Nukhul Red Bed sands and conglomerates,
while the East Arta lease is typically from the calcareous Upper Nukhul Formation. Porosity in the
Arta sands is typically in excess of 30 percent with corresponding high permeabilities in the
thousands of millidarcies. Two conglomeratic rock types have also been identified, with differing
characteristics. The first, a high permeability conglomerate is matrix-supported, with the matrix
sands exhibiting similar permeabilities to the clean sandstone rock type. However, porosity is lower
in this unit as the conglomerate clasts reduce the overall storage capacity. It is expected this rock
type will behave similarly to the clean sandstone rock type, with potentially some minor reduction
in flow rate due to minor baffling effects of the conglomerate clast material. Permeability
measurements taken within the matrix sand of the conglomerate rock type show it to be of
comparable quality to the clean sandstones.
The second conglomerate rock type is described as a limey conglomerate, with overall lower
permeability due to cementation. Core analysis of this unit shows porosities in the range of 8 to 15
percent and permeabilities of 1 to 5 millidarcies.
The calcareous Upper Nukhul Formation produces primarily in the East Arta lease from moderate
porosity limestones, typically 12 to 19 percent, with low permeabilities, typically less than
1 millidarcy.
Page: 45 of 199
Thirteen wells were petrophysically evaluated across Arta and East Arta. GLJ’s analysis was
consistent with a provided third party petrophysical report commissioned by the Group in 2015 for
use in a field simulation model. The results of GLJ’s analysis, combined with additional wells
evaluated in this third party report were used to establish low, best and high estimate petrophysical
cases.
Pool area and net pay thickness were determined from the mapping provided by the Group and then
combined with the low, best and high estimate petrophysical interpretations to determine final
estimates of OIIP. Volumetric parameters for the Lower Nukhul Red Bed sands are provided below.
Oil Reservoir Parameters Arta & East Arta Field
Lower Nukhul Red Bed Formation
Reserves Classification Area (ac)
Proved Plus Probable 880 63.0 18.0 25.0 1.06 54,783
Proved Plus Probable Plus Possible 880 63.0 18.0 18.0 1.06 59,896
Hydrocarbon pore volume maps for the Arta and East Arta Fields, as provided by the Group, are
presented as Maps 24 and 25.
Hana and Hana West
The Hana Field produces from the Markha Member of the Kareem Formation. The Markha
Member shows closure against a seismically-defined east-dipping fault on the western edge of the
development lease, with expected lateral closure to the northwest and southeast of the development
lease. A downdip water leg with an estimated original OWC of -4,660 mSS, determined from the
Hana-01 well, was used to define the lower limit of the pool.
The provided Petrel model was reviewed for both the Hana and Hana West Fields and found to tie
well data acceptably. Gross rock volumes were exported from Petrel for use in volumetric
estimates.
Eleven wells were petrophysically evaluated across the Hana and Hana West Fields. Analysis of
these wells showed increasing water saturations on the eastern edge of the pool, close to the OWC,
resulting in lower net pay and corresponding net-to-gross ratios in this area.
The Hana West Field is producing from the Asl sands of the Rudeis Formation within a fault-
bounded block structure. The structure is referred to by the Group as a ‘teepee structure’. The Asl
Page: 46 of 199
sands can be divided into a number of sub-members; however, GLJ has calculated in-place
hydrocarbon volumes for the entire Asl A and Asl B package.
Volumetric parameters for the Hana Markha and Hana West Asl A&B sands are provided below.
Oil Reservoir Parameters Hana & Hana West Field
Field Zone Area (ac)
Hana West Asl A-B 880 63.0 18.0 25.0 1.06 54,783
Hydrocarbon pore volume maps for Hana and Hana West, as provided by the Group, are presented
on Maps 26 through 28.
Hoshia
The Hoshia Field produces from both the Nukhul and Rudeis Formations. The evaluation of the
Nukhul was done by decline analysis only and no geologic review was conducted. Hydrocarbon
pore volume mapping was provided to GLJ for the Rudeis Formation. GLJ evaluated three wells
across the pool and found the output hydrocarbon pore volume at each well to match the provided
mapping very well. Estimates of OIIP were taken from this mapping and presented below.
Zone Area (ac)
Net Pay (ft)
Rudeis B 594 26.3 18.7 24.5 1.05 16,290
Hydrocarbon pore volume maps for Hoshia, provided by the Group, are presented on Maps 29 and
30.
References El Nady, Mohamed & S. Mohamed, Naglaa. (2016). Source rock evaluation for hydrocarbon generation in Halal oilfield, southern Gulf of Suez, Egypt. Egyptian Journal of Petroleum. 25. 383-389. 10.1016/j.ejpe.2015.09.003.
Page: 47 of 199
WEST GHARIB PERFORMANCE REVIEW, RESERVES AND DEVELOPMENT FORECAST
Proved, probable, and possible reserves have been assigned through a combination of decline
analysis, volumetrics and by analogy. Gas is not conserved in the West Gharib Concession.
Arta and East Arta
Main Arta: Red Beds
Producing reserves have been assigned to 11 Red Bed oil wells using a combination of decline and
volumetric analysis, with additional consideration given to the ‘2016 Red Beds Simulation Study’.
Production from the Red Beds pool commenced in 2010. By 2011, the pool pressure had dropped
from 1,617 to 829 psia. As a result, the Group drilled two water injection wells which would provide
pressure support to the pool. As of the analysis date, the Red Beds were producing at an estimated
3,048 bopd with a water cut of 61 percent. Water injectors are located in the downdip water leg on
the east side of the pool and are currently injecting at approximately 8,187 bbl/d with cumulative
injection of 17,479 Mbbl. The overall recovery factor for producing reserves considers the level of
development that has occurred as of the analysis date of this evaluation, with the most recent two
drills on production in early 2017. Overall recovery factors of 28.7, 29.7 and 30.2 percent were
assigned to the proved, proved plus probable and proved plus probable plus possible cases,
respectively. Probable and possible undeveloped reserves

transglobe energy corporation competent person's report effective december

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