Details of OKL’s Chief Petrophysicist, Jeremy Daines, can be found below together with some atypical technical insights.

If you would like to get a cost estimate for Oleum Khaos to undertake your Petrophysical project, you will need to register / log-in and then provide info on the wells, intervals, input & output data, plus deliverables.

It’s important to gather these data before starting.

For commercial reasons, please be aware that project cost estimates are for existing, or valid potential clients, not the general public.

Peer Assist & Peer Review

Jeremy has undertaken a large number of geological, 3D static model and petrophysical peer assists plus peer reviews.

Having an independent technical review is highly recommended, not least to avoid having to re-work a project due to failing to pass a quality assurance milestone.

It is simple and very cost-effective to utilise Jeremy’s 30+ years of technical experience to review your own project. Use the basic cost estimator below to find out how cost effective this can be.

Select the number of presentation slides, and/or number of report pages, to be reviewed to get a cost estimate.

Petrophysical / Geoscience Presentation review. Number of Slides =

Petrophysical / Geoscience Report review. Number of Pages =

2011 – Present: Chief Petrophysicist, Oleum Khaos

Projects: UK – Claymore, Scapa, Tartan, Montrose, Piper, Auk, Wood, Highlander & South Morecambe fields. Romania – Viforata field. Nigeria – Ughelli field. Cabinda – Castanha field. Russia – Pottymsko-Inginsky, Vostochno-Inginsky & Palyanovo blocks.

Unitisation & Redetermination training courses in Portugal & The Netherlands.

2005 – 2011: Petrophysical Advisor, Hess UK

Projects: UK – Cambo, Rosebank, Schiehallion, Clair & York fields. Australia – Glencoe, Briseis, Nimblefoot & Warrior discoveries. Egypt – Abu Sir, Al Bahig, El King & El Max discoveries. Algeria – BMS field. Azerbaijan – Azeri, Chirag & Guneshli fields. Russia – Bulatovskoye field. Denmark – South Arne field.

2003 – 2005: Chief Petrophysicist, Oleum Khaos

Projects: UK – Trent, Tyne, Glein, Pickerill & Waveney fields. Algeria – Gassi El-Agreb field.

1989 – 2003: Senior Geoscientist, Gaffney, Cline & Associates

Numerous projects worldwide encompassing license terms, exploration, appraisal, development, reserves assessment, competent persons reports, unitisation & redetermination, training courses.

See the Regional Experience section below.

DOWNLOAD JEREMY’S FULL CV

Listed below, in country order, is a summary of the varied, worldwide geological, petrophysical & engineering experience, including fields & wells, gained since 1989

Project Description Field Name(s) Well Name(s)
Review of Triassic & Ordovician reservoirs in well BRDW-1 Brides West (BRDW) BRDW-1
Quality control and selective evaluation of 53 wells for input to 3D model El Agreb AR-2 to 49, AR-80 to 91
Petrophysical interpretation of 2 well's logs El Gassi GS-9z & GS-33
Interpretation and QC of Zotti (AR-70) as part of a 4 day workshop for geoscientists Zotti AR-70
Peer review of Algerian 5th Round Licence prospectivity
Interpretation of selected Devonian undeveloped discoveries as part of the 6th Licensing Round ZRF, ECF, RJ, HBH & ZRFW
Project Description Field Name(s) Well Name(s)
Reservoir characterisation of the Troncoso Inferior and Chorreado Inferior reservoirs of the El Porton field, Argentina, for a small independent El Porton
Reservoir characterisation and field study of the Argentinian Puesto Hernandez field for a National Oil Company Puesto Hernandez
Project Description Field Name(s) Well Name(s)
Petrophysical review in support of a reserves and deliverability study of the Australian Gilmore gas field, for bank financing Gilmore Gilmore 1, 3, 4A, Phfarlet-1,2
Audit of the Australian Gilmore Field reserves assessment undertaken by an independent consultant, related to an electricity supply agreement Gilmore G-1, G-2, G-3, Phfarlet-1&2
Analysis of Harriet field production, for a small independent Harriet
Reserves assessment of the Harriet field, for a small independent Harriet
Assessment of production testing of the Rosette-1 well, for a small independent Rosette Rosette -1
Well planning, operational petrophysics & post drilling evaluation of 4 NW Shelf exploration wells Glencoe-1, Briseis-1, Nimblefoot-1 & Warrior-1
Project Description Field Name(s) Well Name(s)
Petrophysical review of the field Operator's work and assessment of an independent consultant's initial reserves review
Azeri-Chirag-Guneshli
Provision of a 2 week course on international approaches to reserves assessment
Project Description Field Name(s) Well Name(s)
Petrophysical and Field Study of the Sangu field for a super-major
Sangu
Project Description Field Name(s) Well Name(s)
Review of the Operator's petrophysical evaluations of the Castanha wells
Castanha Castanha-1,2,3,3st,4,5,6,7,8,9,10,11,12 & 13
Project Description Field Name(s) Well Name(s)
Petrophysical interpretation of Sedigi 1A and Sedigi 2 wells, for a super-major
Sedigi Sedigi-2, 1A
Project Description Field Name(s) Well Name(s)
Reservoir characterisation and reserves assessment of Block 9 of the Karamay field
Karamay
A review of the recent history of drilling activity in China
Background material for proposal to assist the Chinese National Oil Company in the development of the Shan-Gan-Ning Basin in Northwest China
Project Description Field Name(s) Well Name(s)
Petrophysical audit of the Colombian Lilia-10, ST2 well logs (operated by a small independent)
Lilia Lilia-10, ST2
Project Description Field Name(s) Well Name(s)
Petrophysical interpretation of the LJM-1 & 2 wells as part of a pre-feasibility study for the maximum recovery of liquids from the LJM gas field
Litechendjili Litechendjili-1,-2
Project Description Field Name(s) Well Name(s)
Peer Assist & Review of the South Arne RIGS (northern) field development for a medium independent
South Arne
Assessment of North Sea operating companies as potential partners for a small European independent
Project Description Field Name(s) Well Name(s)
Field reviews of Ecuador related to a complete review of a medium independent's reserves, linked to loan financing
Coca Payamino
Project Description Field Name(s) Well Name(s)
Petrophysical review of selected Egyptian fields in advance of a small independent South Asian client's potential farm-in
North July, EGJ, South West Gebel El Zeit
Petrophysical evaluation of thin beds / low resistivity pay using semi-stochastic method to account for poor input data
Abu-Sir-1x, Al-Bahig-1x, El-King-1x & El-Max-1x
Project Description Field Name(s) Well Name(s)
Petrophysical review of Tertiary discovery in 6004/16-1
Marjun 6004/16-1 & 1z
Project Description Field Name(s) Well Name(s)
Project Inogate 9702 Hydrocarbon Potential Assessment Executive Summary Final Report September 1999 - December 2001
Project Description Field Name(s) Well Name(s)
Field reviews of Gabon related to a complete review of a medium independent's reserves, linked to loan financing
Oguendjo West B&C
Project Description Field Name(s) Well Name(s)
Proposal for Feasibility Study of Epsilon Field
Epsilon E-1, E-1AS
Production evaluation of the Greek Prinos and South Kavala fields for a potential investor
Prinos & South Kavala
Reservoir characterisation and reserves assessment of the Prinos and South Kavala fields, Greece
Prinos & South Kavala
Project Description Field Name(s) Well Name(s)
Review and assessment of the operator's log interpretation of a fractured metamorphic basement reservoir in Hungary
Kiskunhalas NE-N K-38/A, K-127, K-64
Project Description Field Name(s) Well Name(s)
Petrophysical review of the Telisa Sand and Batu Raja limestone reservoirs in the Kaji-Semoga field, as part of the annual reserves update for a small independent
Kaji-Semoga KS-112, KS-121
Core-based reservoir characterisation of wells in the KRA and KG fields, for a small independent
KRA KRA-3X
Information and report on the reservoir geology of the KRA field, plus technical assessment and financial evaluation of the PSCs
KRA
Audit of a medium independent's reports on the Kakap PSC, KRA/KG field's reserves
KRA & KG KG-1X, 3X, 5X, KRA-1X, KRA-3X,
Petrophysical review of the Soka and Kaji fields for a small independent
Soka & Kaji Soka-4, Kaji-118
Petrophysical Review of Turitella-1, Belemnite-1, Nummulites-1 wells, for an independent reserves assessment for a small Far Eastern independent
Turitella, Belemnite, Nummulites Turitella-1, Belemnite-1, Nummulites-1
Project Description Field Name(s) Well Name(s)
Petrophysical review of logs in South Pars well SPO-1 for the operator
South Pars SPO-1
Project Description Field Name(s) Well Name(s)
Petrophysical review and reserves assessment of the Corrib field, in support of an independent evaluation of the Corrib development project
Corrib 18/20-1, 18/20-2Z
Project Description Field Name(s) Well Name(s)
Provision of a 2 week course on international approaches to reserves assessment in Almaty
Project Description Field Name(s) Well Name(s)
Economic Limit Determination Study
Project Description Field Name(s) Well Name(s)
Reservoir characterisation and reserves assessment of the F38 field for a super-major
F38 F38-1
Reservoir characterisation and reserves assessment of the F9 field for a super-major
F9 F9-1,F9-2
F-9 & F-12 Gas Fields Reserves Audit & Certificate, Block SK8, Offshore Sarawak
F-9, F-11, F-12
Petrophysical review and reserves assessment of the Jintan field, for a medium independent
Jintan Jintan-3
Reservoir characterisation and reserves assessment of the Jintan field for a super-major
Jintan J-1,2,3
Reservoir characterisation and reserves assessment of the Laila field for a super-major
Laila Laila-1, Laila-2
Petrophysical evaluation of three wells as part of an independent audit of gas reserves in Block SK-8 for a medium independent
Selasih, Saderi, Cili Padi Selasih-1, Saderi-1, Cili Padi-1
Field summaries for the fields supplying the Malaysian LNG project
Unitisation & Redetermination workshop for a super-major in Malaysia
Unitisation & Redetermination Course for a Malaysian consortium in Kuala Lumpur
Two Unitisation & Redetermination Courses for a National Oil Company in Kuala Lumpur
Project Description Field Name(s) Well Name(s)
Field study, petrophysical interpretation and reserves assessment of the Kudu field, for a super-major
Kudu Kudu-1, 2, 3, 4
Project Description Field Name(s) Well Name(s)
Reservoir characterisation and development feasibility study of certain offshore shallow gas discoveries, for a European small independent
A15-A, B17-A, D Prospect A15-3, B17-6,
Groningen Field Reserves in Holland & Germany
Groningen
Multi-client Unitisation & Redetermination Course in The Hague
Project Description Field Name(s) Well Name(s)
Independent assessment of the Toka-1 well, in the Taranaki Basin, linked to a gas sales agreement with the Operator
Toka Toka-1
Project Description Field Name(s) Well Name(s)
Audit of in-place volumes, including petrophysics undertaken by an independent consultant
Ughelli East & West
Unitisation & Redetermination Course for a Super-Major in Port Harcourt, Nigeria
Unitisation & Redetermination Course for a Super-Major in Lagos, Nigeria
Project Description Field Name(s) Well Name(s)
Summary of oil and gas fields in North West Europe reserve volumes and changes with time
Multiple
Project Description Field Name(s) Well Name(s)
Detailed reservoir study of the complex Embla Field, for a large independent
Embla 2/7-9X, 2/7-23S, 2/7-20X, 2/7-21S 2/7-25S, 2/7-26S, 2/7-27
Core-calibrated reservoir characterisation of the Snorre field
Snorre
Core-based reservoir and fluid characterisation study of the Snorre field, for a medium independent
Snorre
Detailed reservoir characterisation of 48 wells in the Troll oil and gas field
Troll
Reservoir characterisation and reserves assessment of the Veslefrikk field for a large independent
Veslefrikk 30/3-A2,3R,5,6
Unitisation & Redetermination Course for a National Oil Company in Stavanger
Unitisation & Redetermination Course for a Super-Major in Stavanger
Project Description Field Name(s) Well Name(s)
Integrated Petroleum Engineering Study of the Natih-E & Shuaiba Reservoirs of the Burhaan Main Field for a National Oil Company
Burhaan Main BRN-1,2,3,6
Project Description Field Name(s) Well Name(s)
Detailed field study of the Qadirpur field in Pakistan
Qadirpur
Petrophysical interpretation of wells in the Uch field, Pakistan, in support of financing
Uch Uch-2, -3, -4, -5, -6, -8, -9, -10
Project Description Field Name(s) Well Name(s)
Background information on the Iagifu and Hedinia Fields, plus petrophysical review of Iagifu-7X's interpretation
Iagifu Iagifu-7X
Report on the Petrophysics & Log Analysis of wells in the Iagifu/Hedinia Field
Iagifu Iagifu-7X
Petrophysical review and reserves assessment of the Toro and Digimu reservoirs in the Iagifu, Hedinia and Agogo fields, related to development financing
Iagifu, Hedinia, Agogo IDT-1, 3, 6, 7, 8, IDD-2, 3, 4, ADT-1, 2, ADD-2, A-2X, AGD-1, ADD-3
Review of Hedinia 1-X as part of the Kutubu field reserves update, for financing purposes.
Kutubu Hedinia 1-X
Project Description Field Name(s) Well Name(s)
Technical adviser to a major US-based Power Generator, regarding potential development of Zielona Gora gas fields for electricity generation
Zbaszyn-Babimost, Kargova-Wilcze, Jastrzebsko and Paproc West (Zielona Gora Gas Fields)
Project Description Field Name(s) Well Name(s)
Assessment of a partner's interest in the Al-Rayyan Field
Al-Rayyan
Project Description Field Name(s) Well Name(s)
Application of a Thomas-Stieber model to the petrophysical evaluation of 100+ old onshore wells
Viforata Dealu-Batran Area
Project Description Field Name(s) Well Name(s)
Peer review of a small independent Russian operator’s innovative Thomas-Stieber based petrophysical evaluation of 160 wells in the West Siberian Pottymsko-Inginsky, Vostochno-Inginsky & Palyanovo blocks. Provided conclusions & recommendations to assess uncertainty plus potential issues related to 3D static modelling.
PI, VI & PA Licenses
Petrophysical advice to SamaraNefte on the Bulatovskoye & other fields in Samara province
Bulatovskoye
Independent review of a newly formed oilfield service company operating in Russia
Project Description Field Name(s) Well Name(s)
Information on Upstream Regulation & Guidelines for the development of non-associated gas production
Project Description Field Name(s) Well Name(s)
Petrophysical interpretation of offshore well, E-BA-1 for a National Oil Company
E-BA E-BA-1
Petrophysical review and reserves assessment of the E-M field, for a National Oil Company
E-M E-M1, 2, 3, 4, 5, 6
Assessment of a draft gas sales agreement and recommendations for improvement with respect to estimating remaining reserves
Pande, Temane
Project Description Field Name(s) Well Name(s)
Regional review of Sudan's oil & gas export and import status as part of an assessment of a European National Oil Company's market assessment
Project Description Field Name(s) Well Name(s)
Integrated Field Studies on the Akash, Maleh and Sarhit-Shdeha fields for a National Oil Company
Akash, Sarhit-Shdeha, Maleh
Detailed field study of the El Ahmar field for the National Oil Company
El Ahmar
Full field study including reservoir characterisation of the Judea Limestone, Lower Rutbah and Mulussa F reservoirs in the El-Ward field for a National Oil Company
El-Ward EWN-101, 102, 103, 104, 105
Review of a Super-major's petrophysical report on Omar field in the Middle East
Omar
Full field study including reservoir characterisation of the Rutbah and Mulussa F reservoirs in the Shahel field for a National Oil Company
Shahel SHL-101, 102, 103, 104
Full field study including reservoir characterisation of the Mulussa F reservoir in the Tanak field for a National Oil Company
Tanak Tan-101, 102, 103, 104, 105, 106, 107, 108
Full field study including reservoir characterisation of the Rutbah reservoir in the Thayyem field for a National Oil Company
Thayyem (Rutbah) TH-1, 102, 103, 104, 105, 107, 108, 109, 110, 111 & 112
Project Description Field Name(s) Well Name(s)
Petrophysical review and full field evaluation of Dolphin field development, for a large independent
Dolphin D-3,4
Project Description Field Name(s) Well Name(s)
Review of a petrophysical evaluation of Lam Field, undertaken by an independent consultant, for a small independent
Lam Lam-10/51, 21/62A, 75/79, 13/96
Review and operations plan for the Zhdanov and Lam fields, including production and processing infrastructure
Lam and Zhdanov
Production operations and facilities inspection programme for the Lam & Zhdanov fields for a small independent
Lam and Zhdanov
Consolidation of significant volume of Soviet era wireline logs from the Lam and Zhdanov fields, plus construction of digital database of well data
Lam and Zhdanov
Petrophysical evaluation of newly acquired well data in the Lam & Zhdanov fields, plus update of hydrocarbons in place and reserves, for a small independent
Lam and Zhdanov
Provision of a 2 week course on international approaches to reserves assessment in Ashgabad
Background information regarding a Turkmeni delegation to Norway to review Oil & Gas related regulatory systems and structures
Project Description Field Name(s) Well Name(s)
Alba field review and petrophysical evaluation related to a complete review of a medium independent's reserves, linked to loan financing
Alba
Petrophysical review of the Alba, Galleon and Ensign fields as part of a valuation exercise for a medium independent
Alba, Ensign, Galleon,
Review of SCAL from 14/26a-8 for application in the interpretation of 13/30-3
Atlantic & Cromarty 13/30-3 & 14/26a-8
Petrophysical interpretation of the Audrey field wells related to a complete review of a medium independent's reserves, linked to loan financing
Audrey All
Review of a UK small independent's interests in UK Licences P450 and P454 for potential acquisition
Boulton, Orca
Audit report on the Britannia field's evaluation of sand body properties using conventional core data and log data
Britannia
Petrophysical review of wells as part of an evaluation of a large independent partner's interest in the UKCS Britannia Field
Britannia 15/30-9 & 16/26-24
Petrophysical characterisation and reserves assessment of the Britannia field for a medium independent
Britannia 15/30-9, 16/26-24, 16/24-16
Independent evaluation of UK Block 9/18A
Buckland, Gryphon
Review of the petrophysical evaluation of wells in the Buzzard field, for a small UK independent
Buzzard
Review of the MRIL & Mobility-derived permeability in the Cambo Tertiary reservoir oil & gas discovery
Cambo 204/10-1 & 204/10-2
Reservoir characterisation and reserves assessment of the Claymore field for a medium independent
Claymore
Complete re-evaluation of the Main Area Claymore field's 50+ wells using a new permeability predictor
Claymore
Columba field review and petrophysical evaluation related to a complete review of a medium independent's reserves, linked to loan financing
Columba
Reservoir characterisation and reserves assessment of the Everest field for a large independent
Everest 22/14A-2, 22/10A-3, 22/10A-2, 22/10A-4, 22/10A-5, 22/9-3, 22/9-2, 22/9-4
Independent evaluation of a medium independents UK licence interests in: P016, P019, P020, P030, P064, P065, P066, P101, P133, P143, P291, P292 as part of a dispute between partners
Everest, Drake, Frobisher, Davy, Woolaston
Petrophysical interpretation of Galleon field's wells related to a complete review of a medium independent's reserves, linked to loan financing
Galleon 48/20-1, 48/15A-5
Petrophysical Peer Assist of the Galley South field for a medium independent
Galley South
Petrophysical evaluation of Southern North Sea Glein discovery wells for input to 3D model
Glein 48/11a-12
Evaluation of a small independent's UK licences P137 (Block 42/15A, B), P244 (Block 22/1) and P244B (Block29/6A) for acquisition by a large independent
Glenn
Petrophysical Peer Assist of the Highlander field's Cretaceous reservoirs for a medium independent
Highlander
Hutton field review and petrophysical evaluation related to a complete review of a medium independent's reserves, linked to loan financing
Hutton
Kilda field review and petrophysical evaluation related to a complete review of a medium independent's reserves, linked to loan financing
Kilda 16/26-21 & 21z
Review & assessment of a US medium independent's data on certain UK Licences as part of a dispute related to an acquisition
Leman, Indefatigable, Montrose, Amethyst, Arbroath, Everest, Lomond, Greater Drake
UKCS Lyell field review and petrophysical evaluation related to a complete review of a medium independent's reserves, linked to loan financing
Lyell
Co-development of a "shared earth" model of the Magnus Field for a super-major
Magnus
Petrophysical review of the Tertiary sands in 204/16-1
Marjun 204/16-1
Independent review of the Miller Field gas reserves related to the privatisation of a UK power generation company
Miller
Petrophysical review of the Montrose field's 4 cored wells
Montrose 22/17-1, 22/18-1, 22/17-A2 & 22/17-A12
Review of the operator's and subsequent independent petrophysical evaluations of the South Morecambe field
Morecambe South
Assessment of South Morecambe's core data & identification of issues related to horizontal & vertical plug measurements
Morecambe South
Full field review, including reservoir characterisation and reserves assessment of the North and South Morecambe fields for a large independent
Morecambe South & North
Review of a UK small independent's upstream assets in UK, Netherlands, Italy and Tunisia
Multiple
Reservoir characterisation and reserves assessment of the Ness field for a large independent
Ness 9/13B-45Z, 9/13B-38Z
Ness field revised field development information
Ness
Petrophysical summary of Ninian from 1988-89 Simulation Study related to a complete review of a medium independent's reserves, linked to loan financing
Ninian
Petrophysical evaluation of Southern North Sea Pickerill field wells for input to 3D model
Pickerill
Independent evaluation of a medium independents UK licence interests in: P620 & 621 (3/13b & 3/18b), P495 (Block 9/17b), P573 (Block 12/13), P645 (Block 19/2), P592, 596 & 600 (Blocks 20/4b, 22/10b & 23/6), P378 (Block 20/14), P652 (Block 21/28b),P499, 508 & 509 (Blocks 28/25, 29/26, 29/27), P449 (Block 43/25a), P461 (Block 48/12b), P463 (Block 48/17b), P521 (Block 49/2), P524 (Block 49/9b), P560 (Block 204/29) and onshore licences; EXL 060, 080, 133, 138, 158
Pickerill, Claymore, Lancelot - Guinevere, Avalon
Project Manager for complete petrophysical re-evaluation of the Piper field for a medium independent
Piper
Complete petrophysical re-evaluation of West of Shetland Rosebank discovery wells.
Rosebank 205/1-1, 213/26-1 & 1z, 213/27-1z, 213/27-2, 213/27-4, 4x,4y & 4z
Review & assistance in operations of the Rough Field gas storage facility
Rough
An evaluation of the access boreholes in an onshore UK LPG storage cavity for a major chemical company
Saltholme Saltholme-90 & 57
Re-evaluation of the Scapa Sands to accurately describe poorly resolved net to gross issues related to cementation
Scapa 14/19-9, 14/19-15, 14/19-18, 14/19-19, 14/19-21, 14/19-25, 14/19-E1,E2,E3,E4,E5Y,E6,E7,E8,E9 & E9Z
Petrophysical evaluation of Scott field well 15/22-4
Scott 15/22-4
Reservoir characterisation and reserves assessment of the Scott field for a large independent
Scott 15/21A-34, 15/22-7, 15/22-6Z, 15/21A-39Z, 15/22-4
Review of a potential financing opportunity regarding the Scott Field Development
Scott
Strathspey field review and petrophysical evaluation related to a complete review of a medium independent's reserves, linked to loan financing
Strathspey
Project Manager for complete petrophysical re-evaluation of the Tartan field, for a medium independent
Tartan
Petrophysical evaluation of Tyne field wells for input to 3D model
Tyne 44/18-1, 44/18-2 & 2Z, 44/18a-5, 44/18-T1, T1Z, T2, T3A, T5, 44/18-4A,44/13-1, 44/17-3
Petrophysical evaluation of Waveney field wells for input to 3D model
Waveney 48/22-4, 48/16-1, 48/17a-6 & 6ST, 48/17b-5, 48/17a-9, 48/17-1, 48/17c-w2, 48/17c-12z, 48/17c-12,48/22-3, 48/18c-8
Peer review of the Wood field's petrophysical evaluations for a medium independent
Wood 22/18-6 & 22/18-7
Review of saturation height functions and the Operator's reservoir model
York
For UKCS mature and frontier quadrants, define play types, typical reserve sizes or prospective volumes to support a medium independent's exploration strategy, using realistic development cost assumptions. Exploration success by play type and likely future success rates up to 2020
Input to standardised Unitisation and Redetermination Technical Procedures
An investigation into the internal chemical and physical environment of the BOP choke line hose on the Ocean Odyssey rig, September 1988, plus technical support during the Ocean Odyssey Inquiry in Aberdeen
Petrophysical evaluation of well 22/27A-3Z (ST) for a small independent
22/27A-3Z (ST)
Presentation on the new PRT Environment in the UK North Sea, to the Institution of Chemical Engineers, Aberdeen
Review of the geological prospectivity of the major UKCS basins plus the likely future oil and gas reserves via probabilistic analysis, for a small independent
Unitisation & Redetermination Course for a medium independent operator in the UK
Exploration petrophysical screening of the Mey Sandstone reservoir properties in UK Quad 30, for a medium independent
30/6-3, 30/6-4, 30/7a-2, 30/7a-10, 30/12b-2, 30/13-1, 30/13-2, 30/13-5, 30/13a-9, 30/14-3, 30/14-4, 30/17b-5, 30/18-5, 30/18-6
Exploration petrophysics of the Lower Cretaceous & Upper Jurassic in selected Quad 12 & 13 wells
12/24-1,12/24-2,12/24-3,12/25-1,12/25-2,12/25-4Y,13/22a-14 & 13/22b-4
Project Description Field Name(s) Well Name(s)
Provision of a 2 week course on international approaches to reserves assessment in Kiev. Including delegates from Georgia, Moldova & Armenia
Project Description Field Name(s) Well Name(s)
Provision of a 2 week course on international approaches to reserves assessment in Tashkent. Including delegates from Kyrgyzstan & Tajikistan
Project Description Field Name(s) Well Name(s)
Unitisation & Redetermination Course for the National Oil Company in Hanoi
Project Description Field Name(s) Well Name(s)
Database of world-wide offshore oil and gas facilities for a Far Eastern National Oil Company

Jeremy’s primary technical expertise is Petrophysical interpretation from a geological foundation. This foundation can be significant because, without knowledge of depositional systems, bed-forms and lithology; understanding what logging tools are providing and what valid information can be gleaned from them, is the first critical step in evaluation.

Jeremy was fortunate to work with Dr Paul F Worthington and still collaborates with him. One of Dr Worthington’s many strong points is the number of high quality papers he’s published, relating to pragmatic petrophysical evaluation.

The following papers, published by Dr Worthington, are highly recommended:

  • Conjunctive Interpretation of Core & Log Data Through Association of the Effective & Total Porosity Models, 1998
  • The Evolution of Shaly-Sand Concepts in Reservoir Evaluation, 1985
  • Scale Effects on the Application of Saturation-Height Functions to Reservoir Petro-facies Units, 2001
  • Application of Saturation-Height Functions in Integrated Reservoir Description, 2002
  • The Effect of Scale on the Petrophysical Estimation of Intergranular Permeability, 2004
  • The Role of Cut-Offs in Integrated Reservoir Studies, 2005
  • Optimizing the Value of Reservoir Simulation Through Quality-Assured Initialization, 2014

All Petrophysicists plus Geoscientists and Reservoir Engineers can benefit significantly from the topics covered in the papers above.

A Petrophysicist is not defined by the software he or she can use. It doesn’t matter whether an Operator uses Techlog™, Interactive Petrophysics™, Geolog™ or any other package. None of these applications will give rise to better results because it is the expertise of the Petrophysicist who undertakes proper data quality assurance and then cerebral, iterative analysis. The software is simply a tool; however, many people now give the software far too much weighting. If you can drive Techlog™ or Petrel™ you are now an experienced Petrophysicist or Geologist / Modeller. I beg to differ.

Jeremy can provide Operators with the expertise to achieve the lowest uncertainty data, including whole core acquisition, handling and analysis, encompassing conventional and special core analysis programmes.

Understanding uncertainty is fundamental. Many people consider stochastic methods provide the best way to understand uncertainty. In theory this is the case; however, in practice we consistently under-estimate the range of uncertainty in input parameters, assume probability density functions which may be incorrect, fail to assign, or assign, incorrect dependencies. This leads to a range of results which staff and Management tend to believe is accurate. It generally isn’t. Plus, the range of results may not be realistic in terms of what each scenario means. I think Shell started to realise their stochastic reservoir model-derived in-place volume estimates were flawed because many of the reservoir models were simply untenable.

A further nail in the coffin of stochastically derived estimates is the significant difficulty in auditing them. If it can’t be audited then really, it shouldn’t be used. Don’t get me started on auditing 3D reservoir models!

Jeremy’s preferred approach to petrophysical uncertainty is not to derive a single set of reservoir properties. In theory the objective of all technical evaluations is to derive the Most Likely properties, not the Mean or P50. In anything other than a uniform clean sand, estimating in isolation, the Most Likely properties, tends to be difficult, if not impossible. However, this is what the majority of Petrophysicists try to do, on a day-to-day basis.

There is a more rigorous way to describe some of the uncertainty. The validated raw data provides low and high values of each input parameter. The key words here are valid data. Thorough data quality assurance is absolutely essential before any evaluation is undertaken, otherwise invalid data gets adopted. Once the valid minima & maxima are known these provide boundaries for uncertainty scenarios. They are unlikely to describe the full range of uncertainty because the data probably doesn’t reflect the total population. But they are, at least, auditable data-driven parameters.

Two petrophysical scenarios can easily be constructed using the Low & High input properties of the porosity model. This is easy and very auditable. The same approach can be used for Shale Volume, mineral proportions, permeability and water saturation. Now I hear you say; using all the Low (or High) estimates together is unrealistic; which I agree.

The probability of all the low parameters combining in nature is very low. Which is actually very useful because we can adopt these results as sort of equivalent to a P01 in the stochastic world, suggesting to Management that it’s unlikely to be less than this, based on the data we have to work with. So, the Low (nominal P01) and High (nominal P99) reservoir properties can be derived in a straight-forward manner.

How does the Most-Likely estimate get derived? Therein is the problem. If the data does not provide an indication of a uni-modal value, then it cannot be derived. In this situation the fall-back is to derive a Mid Case between the Low and High parameters and ensure Management understand this is not the Most-Likely scenario.

There are generally two explanations for inaccurate Petrophysical interpretations; Firstly poor data quality assurance and secondly; the lack of partitioning of different petro-facies. In other words the Petrophysicist fails to separate out the different petro-facies and tries to characterise a mixture of log & core responses with one category. The classic core-plug poro-perm cross-plot is a common expression of this. I don’t recommend anyone uses such a cross-plot without classifying all of the core plugs first. In fact don’t try to derive poro-perm correlations using such cross-plots, at all.

Why do we have to deal with such uncertainty? The root cause is a misunderstanding, by Operators, of the value of information.

Operators perceive that obtaining whole core is too expensive and that it’s more cost-effective to use other means such as logs. This is actually a fallacy.

Consider the levels of uncertainty in reservoir & fluid properties when estimated from (particularly uncalibrated) logs versus, for example, whole core. In theory, if the whole core is obtained correctly and the correct core plug handling and analyses are undertaken; then the sedimentological, lithological and reservoir property, plus fluid uncertainty, is minimal or even close to zero.

In other words, we know the answer at the well.

Without whole core of the reservoir, we do not know the answer at the well, we typically make a guess, or with a suitably experienced Petrophysicist; a range of guesses.

The moral of the story is spend the money to get the answer with minimal uncertainty because this allows confident investment or divestment decisions. Get whole core with a minimal suite of logs, perhaps just basic LWD, plus an RFT to confirm free-water levels.

Introduction

As with most things, when you learn something you tend to automatically rely on established approaches and workflows. You’re taught, or read, how to do things and tend to accept these are the best practices and therefore should be utilised. This isn’t always the case.

Petrophysical evaluation is a case in point, where there are a few legacies which, when scrutinised, do not have very solid technical foundations. The Effective Porosity System (EPS) is one of these; however, the vast majority of evaluations of conventional clastic reservoirs utilises this particular system.

As most experienced Petrophysicists know, the first fundamental flaw in the EPS is the estimate of Shale Volume (VSH), from which Effective Porosity (PHIE) and Effective Water Saturation (SWE) are subsequently derived. If (as is almost always the case) VSH is inaccurate; then PHIE and SWE are also inaccurate. This paper is not going to expand on, or discuss in great detail, the technical pros and cons of the EPS; this can be found in the literature. The Total Porosity System (TPS) is technically more robust than the EPS and would be preferred so long as the necessary data has been acquired.

This paper summarises a workflow that derives technically defensible Low-Mid-High estimates of VSH, which can then feed into Low-Mid-High estimates of PHIE, SWE and permeability. The workflows for PHIE, SWE and permeability will be addressed in separate papers; however, in the meantime the experienced Petrophysicist should be able to adapt the approach, described below, to derive a range of PHIE, SWE and permeability estimates.

This “EPS approach” can be adapted to derive three sets of results via the TPS.

The vast majority of Petrophysicists’ “clients” tend not to specify a requirement for a range of petrophysical results. However, all subsurface technical disciplines should, by default, be deriving a technically substantiated range of estimates, in order to account for uncertainty. Sadly, this is not routinely undertaken. Of course, to do this requires more time and more understanding. We should not be producing single, so-called “Base Case” or “Best Technical Estimate” results, without properly describing the upside & downside scenarios.

If your client asks you for a petrophysical evaluation without specifying the porosity system, or the scenarios required; the likelihood is that the client doesn’t understand petrophysics or uncertainty; or maybe they do, but their prepared to wing it, which isn’t really top decile professionalism. In this situation, it’s incumbent on the Petrophysicist to discuss the options with the client (and, if necessary, diplomatically with the client’s Technical Manager); to ensure there’s full understanding of the best porosity system(s) to use, their implications and the need for a range of estimates. If the client (and TM) choose not to follow the Petrophysicist’s recommendations, ensure you’ve made your views clear (for example in an email) and summarise what you’ve been asked to undertake, together with any limitations these give rise to.

Paul Worthington has an excellent summary of using the TPS and EPS together in order to derive what he calls “ground-truthed” results (Conjunctive Interpretation of Core & Log Data Through Association of the Effective & Total Porosity Models, 1998). His approach is highly recommended; however, a range of estimates, is still required.

Shale Volume Estimation

As mentioned above, the estimation of a VSH log is fraught with issues plus, whichever VSH model is adopted, there’s significant uncertainty around this estimate. This uncertainty is “inherited” into the estimate of PHIE and then again into SWE, because VSH and PHIE are inputs to SWE. So, you can see why undertaking a single EPS evaluation is a risky business.

In order to mitigate the issues with estimating a VSH log; below is a relatively simple workflow designed to derive Low-Mid-High estimates of VSH using the Gamma-Ray (GR) as the input log.

This approach is not restricted to solely VSH from the GR; the approach can be adapted to other input logs used to estimate VSH, as well as the input parameters to porosity, permeability and saturation estimates.

The key aspect is identifying realistic Low-Mid-High input values for the Shale Volume model(s), plus Porosity & Saturation model(s).

VSH-GR Workflow

  1. Ensure all borehole environmental corrections have been undertaken and bad log & core data either removed or replaced (I prefer to null bad data rather than replace it).

  2. The available GR data controls the best technical approach. The best quality wireline GR data is acquired at the slowest logging speed, which tends to be with the (pad-based) bulk density tool. So, identify the best GR data over the Zone Of Interest (ZOI). If Spectral GR is available, investigate the CGR and SGR over the ZOI. The Thorium or Potassium logs may be useful, for example, if there are Feldspars, or not (see Crain for more details: https://www.spec2000.net/11-vshgr.htm and leave a donation).

  3. For the reasons above, ideally evaluate the ZOI on a well by well basis, but if this is not feasible, for example, due to the large number of wells; generate normalised input log(s). Typically the GR database will be a mixture of standard wireline (acquired at different logging speeds), spectral GR (often over limited intervals) plus LWD data. These data can be quite disparate and not really suitable for normalisation or multi-well evaluation; hence keeping evaluation to a well by well basis is recommended.

  4. In conjunction with other logs, core analyses, sidewall core information, cuttings, formation pressure plus DST data; interrogate the GR response over the ZOI to understand what the radio-activity represents. As part of this, do other quick-look VSH estimates using logs other than the GR.

  5. Once you have selected the ZOI(s) generate a histogram and cumulative frequency plot of the best GR log, over the ZOI, such as the one shown below:

  6. Decide on what cumulative frequency percentiles to use to describe the “Clean,” low GR intervals and the “Shaly”, high GR intervals. Illustrative values, taken from the distribution above, are shown in the table below:

    Cumulative % GR Value Class
    P05 20 “Clean”
    P10 22 “Clean”
    P15 24 “Clean”
    P85 81 “Shaly”
    P90 92 “Shaly”
    P95 125 “Shaly”
  7. The selection of the ZOI, plus the cumulative percentage values, has a direct impact on the resulting estimates of VSH; so some iteration is recommended before selecting the final parameters. This is discussed in more detail later on.

  8. For each ZOI derive raw VSH GR-Hi, VSH GR-Mid and VSH GR-Lo, using the equations below:

    VSH GR Hi =
    (GR – GR P05)
    (GR P85 – GR P05)
    VSH GR Mid =
    (GR – GR P10)
    (GR P90 – GR P10)
    VSH GR Lo =
    (GR – GR P15)
    (GR P95 – GR P15)
  9. Create final constrained VSH GR Hi, Mid and Lo logs, from the raw logs.

  10. Plot the constrained VSH GR logs in a layout together with the input log(s) and check for suitability. It may be necessary to iterate on the ZOI and/or the “Clean” plus “Shaly” end-points. The three VSH GR logs, shown below, were derived from the GR data in the histogram shown above. The Net-To-Gross (NTG) flags and NTG percentages, based on application of VSH GR < 50%, are also shown. The Gross and “Net” interval thicknesses, for each VSH GR scenario, after application of the VSH GR < 50% cut-off are also summarised:

    Illustration of VSH GR-Hi, -Mid & -Lo Estimates Together With “Net” Flags

      VSH GR-HI VSH GR-MID VSH GR-LO
    Gross Interval (M) 106.38 106.38 106.38
    “Net” Interval (M) 81.24 84.13 88.92
    NTG (%) 76% 79% 84%

    Table of Gross, “Net” & NTG After Applying VSH<50%

Summary

The range in “Net” thickness from 81.24 m to 88.92 m will tend to outweigh the uncertainty range attributed to porosity plus, where valid calibrating data for saturations exist and vertical fluid distribution(s) are well-constrained; NTG uncertainty will outweigh the saturation uncertainty range.

But, if fluid contacts and/or fluid types are poorly constrained, then saturations and/or the definition of Net Pay, can have significant uncertainty ranges; potentially a similar order of magnitude as NTG. This is why it’s essential to incorporate fluid contact uncertainty into all petrophysical evaluations.

The example illustrated above highlights how sensitive the inputs to the VSH GR estimate are, in terms of the resulting NTG. Looking at the input GR log, you could make an argument that the ZOI could be changed; introducing three zones for example: 3080-3095m, 3095-3155m and 3155-3190m. If you have other data to support such a zonal breakdown, then subdivision should be done.

This also demonstrates how inappropriate it is to undertake a single deterministic estimate.

With a range of approximately 8m of “Net” reservoir resulting from the same input GR log but different “Clean” and “Shaly” end-points; it’s essential to derive a range of VSH estimates.

Discussion

I am not recommending the workflow above is the be-all and end-all of EPS petrophysics; it’s not. Worthington’s 1998 paper, referenced earlier, provides an excellent all-encompassing EPS and TPS approach, albeit leading to a single deterministic estimate in each system.

I am recommending that all petrophysics moves away from the single estimate scenario, to an industry-wide default of deriving: Low, Mid (or Most-Likely, if this can be achieved) and High estimates of lithology, porosity, permeability and water saturation. All technical professionals agree with this, but then don’t tend to implement it!

The workflow, described above, provides a good starting point for VSH. The approach can be adapted and expanded to estimate three scenarios of PHIE and SWE, linking with the three estimates of VSH. The approach can be adapted to estimate three cases of VSH from other input logs such as the SP, RHOB, NPHI, etc.

As I’ve discussed previously, I recommend you combine, deterministically, all the pessimistic estimates of VSH, PHIE and SWE to provide what may be close to a P99 scenario; where there’s a 99% chance the actual values are larger. This pessimistic scenario is very useful in terms of estimating a “downside” case, which geomodellers, reservoir engineers and Subsurface Managers really ought to be considering before investing millions of Dollars in appraisal or development.

It’s recognised that combining all pessimistic values is unlikely to occur in reality; however, this is deliberate in order to extend the range beyond the incomplete data actually used to establish the Low, Mid and High scenarios.

The same argument applies to the combination of all optimistic VSH, PHIE and SWE parameters to provide what may be close to a P01 scenario, where there’s a 99% chance the actual values are smaller. This can be considered an “upside” case, which should also be modelled for in-place and recoverable volumes.

Lastly, the long legacy of the EPS and its adoption as the petrophysical model of choice, probably means the industry will continue using it, even though it is technically unsupportable!

Instead of following the petrophysical herd, think about alternative ways of describing potential reservoir intervals, the inter-connected pore volume and permeability within the reservoir intervals, plus the fluid saturations.

Is a single VSH log a good enough parameter to start this process?

No.

Is a range of VSH estimates good enough?

Not really, but it’s significantly better than a single estimate.

Can I estimate (connected) porosity and permeability with reasonable accuracy, without using a VSH?

If so, then you can define reservoir and non-reservoir using these parameters and VSH becomes redundant; wonderful!

The TPS is technically more robust than the EPS; so planning data acquisition for the TPS is highly recommended, whereas reliance on the EPS, is not recommended.

You are welcome to contact me for additional clarification or to share your own applications, or adaptations, of this approach.

© Oleum Khaos Limited (July 2017)

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Oleum Khaos Petrophysical Publications:

1. Chief Petrophysicist, Jeremy Daines’ CV   PDF

2. Jeremy Daines’ Technical Expertise & Approach   PDF

3. Jeremy Daines’ VSH Uncertainty Range Workflow   PDF