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Page 1: Operations Geology Conference 26-27 November 2014

Operations Geology Conference

26-27 November 2014 #OperationsGeology14 Page 1

Operations Geology Conference

26-27 November 2014

Corporate Supporters

Conference Sponsors

Page 2: Operations Geology Conference 26-27 November 2014

Operations Geology Conference

26-27 November 2014 #OperationsGeology14 Page 2

CONTENTS PAGE

Conference Programme Pages 3 - 5 Oral Presentation Abstracts Pages 6 – 74 Poster Presentation Abstracts Pages 75 - 92 Fire and Safety Information Pages 93 - 94

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PROGRAMME

Wednesday 26 November 08.15 Registration

08.55 Welcome: Nick Pierpoint (BG Group)

09.00 Keynote Speaker: Prof Iain Stewart (University of Plymouth) Promoting Contested Geoscience: Communicating the Depths of the Geological Subsurface

Session One: Well Planning Session Chair: Gordon Holm, Kirstin McBeath

09.30 Ian Garrett (Tullow Oil) Well Planning & Delivery: What Well Engineers Want…

10.00 Francis Buckley (LR Senergy) Can We Drill There? Well Location and Top Hole Drilling Hazards

10.30 Jack Lee (Ikon GeoPressure) Kicks and Their Significance in Pore Pressure Prediction

11.00 Break

Session Two: Execution/Case Studies Session Chair: Joanna McKidd, Richard Smout

11.30 Thomas Bond (BP) Managed Pressure Drilling through Mungo’s Salt Diapir

12.00 Ajesh John (Cairn India) Challenges and Uncertainties of Pore Pressure Predictions in High Velocity Over Pressure Formations: An Alternative Vp/Vs Based Approach

12.30 Poster Session - 5 minutes from each poster presenter

13.00 Lunch

Session Three: Execution/Case Studies Session Chair: Pat Spicer, Louise Young

13:55 Video

14.00 Paul Roylance (BP) How the Revised Extent of a Fault Tip on Re-Imaged Seismic Data Impacted the Planning Of a 36 Well Programme

14.30 Tom Sinclair, Jordan Graham (BG Group) Integrated Well Planning and Operations

15.00 Teresa Polo (Repsol) Geological Operations: Integration of Data. Case History in Jaguar-1 Well (Guyana)

15.30 Break

Session Four: Execution/Case Studies Session Chair: Nick Pierpoint, Kirstin McBeath

16.00 Kaleem Anwar (BP) While Drilling Shale Dispersion Tests Improves Drilling Performance

16.30 Alan Grant (Eon) The Tolmount Field – Continual Integrated Learning for Geoscientists and Engineers

17.00 Day Summary: Richard Swarbrick (Swarbrick Geopressure Consultancy)

17.30 -18.30

Wine Reception (sponsored by Geoservices)

19.00 Conference Dinner: Cavendish Hotel

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Thursday 27 November 08.30 Registration

08.55 Welcome: Nick Pierpoint (BG Group)

09.00 Keynote Speaker: Malcolm Brown (BG Group) Where Are We Going As Geologists Within The Industry?

Session Five: Technology Session Chair: Louise Young, Pat Spicer

09.30 Carl Hills (Total) Introduction to the Managed Pressure Drilling Process with Case Study Feedback on Real Experiences in the Field

10.00 Richard Hood (BG Group) Permeability Constrained Pore Pressure Observations from the Chalk Group, UKCS

10.30 Break

Session Six: Technology Session Chair: Kirstin McBeath, Nick Pierpoint

11.00 William Davies (HRH Geology) Deciphering the Formation Fluid Signature in Real-Time Using a New Oil Based Mud Fingerprinting Technique for Mass Spectrometry

11.30 Mike Jackson (BG Group) Well Operations Centres - The Next Step

12.00 Poster Session – 5 minutes from each poster presenter

12.30 Lunch

Session Seven: Competence Session Chair: Richard Smout, Louise Young

13.25 Video

13.30 Haydon Bailey (Network Stratigraphic Consulting Ltd) “What Did Those Micropalaeontologists Ever Do For Us?”

13.50 Christine Telford (CTC GEO LTD) and Stuart Archer (Dana Petroleum) Highlighting the Importance of Teaching Operations Geology: both at MSc level and as part of Continuing Professional Development Programmes

14.10 Brad Powell (Royal Dutch Shell) Shell Canada’s Field Rotation in Operations Geology (FROG) Program – Building Competence in Operations Geologists through Hands-On Rig Site Experience and Vetting Competence by Multi-Disciplinary Assessment

14.30 Tim Herrett (Tim Herrett Limited) and Kirstin McBeath (BP) BP’s Accelerated Development Programme for Operations Geology

14.50 Break

Session Eight: Competence Session Chair: Joanna McKidd, Gordon Holm

15.20 Colin Higgins (OMV) Managing Professional Competence in Operations Geology

15.40 Tim Watts (Dana Petroleum) Operations Geology: Establishing a Profession fit for the 21st Century

16.00 Bill Gaskarth (The Geological Society) Professional Titles with the Geological Society of London (GSL).

16.20 Summary: Richard Swarbrick (Swarbrick Geopressure Consultancy)

17.40 Conference Close: Nick Pierpoint

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POSTER PROGRAMME

Day One

1 Jim Raggatt (Tethys Petroleum) Insights from the Kazakh Steppe

2 Rachael Hutson (BG Group) Automatic Identification of Seismic Geobodies and its Application to Pore Pressure Analysis and Prediction

3 Francis Buckley (LR Senergy) Re-evaluating Shallow Geology in the Central North Sea

4 Neil Cardy (Baker Hughes) Rigsite Geochemical Analysis of Cuttings Enables Optimisation Throughout the Life Cycle of the Well

5 Eyvind Aker (AGR) Seismic Pore Pressure Prediction in the Norwegian Sea, Halten Terrace

6 John David Jackson (Statoil) Kvitebjørn Overburden Study

7 Nader Fardin (LR Senergy) Combined Service for PPFG Prediction and Drilling Performance Support

Day Two

8 Hozefa Godhrawala (Centrica Energy) Definition of an Operations Geologist: The Art of Engaging People and Possibilities

9 Gionata Ferroni (Geolog International) Advanced Surface Logging in the Life-Cycle of a Well

10 Johan Lall (Repsol) Operations Geologists’ Activities Review under the LEAN Methodology

11 Colin Maxwell (Geologix Limited) Automation in Operations Geology – Opportunity or Anathema?

13 Femi Tanimola (Geoservices) Surface Formation Evaluation: A New Approach to Improve, Complement and De-Risk Traditional Formation Evaluation and Characterization Methods

14 Pat Spicer (Dana Petroelum) Time Dependent Bore Hole Stability : New Technology to Address an Age Old Problem

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Oral Presentation Abstracts

(Presentation order)

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Wednesday 26 November

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Keynote Speaker: Promoting Contested Geoscience: Communicating the Depths of the Geological Subsurface

Prof Iain Stewart, University of Plymouth

Subsurface science will play a major role in addressing some of the critical societal and

economic challenges of the 21st Century (energy, minerals, water, waste, hazards). For the oil

and gas sector, that will mean geoscientists (from academia and government as well as

industry) communicating effectively a range of novel, uncertain and contested technical issues

which pertain to an offshore and/or underground realm which is for most people ‘out of sight

and out of mind’. The unfamiliarity of the geological subsurface means that gaining broad

popular support for major energy projects will require professional geoscientists to recast their

specialist technical knowledge in ways that are readily accessed by politicians, civic and

commercial decision makers (e.g. planners), and the wider public. This talk will consider the

nature of this communication challenge, examine current geoscience communication practices,

and examine new approaches to engaging the UK public in ‘contested geoscience’.

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NOTES

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Wednesday 26 November Session One: Well Planning

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Well Planning & Delivery: What Well Engineers Want…

Ian Garrett, Tullow Oil

The interface between the subsurface, operations geology and well engineering groups is a

critical part of the well planning and delivery process. In the past within Tullow, this process has

largely happened in an unstructured manner with different assets providing similar information

in different ways. This has resulted in the need for numerous follow up discussions /

conversations. In some ways these are of value as they can promote a greater understanding,

but this approach can also lead to frustration. As such, in Q2 2013 Tullow well engineering

introduced a formal well delivery process tracked using a software package called WellAtlas

(produced by SPD).

Within this process, there are 3 key interface documents which are designed to strike the

balance between the need for structured written information, but also to promote the

conversations that go along with them. These documents are as follows:-

1) The New Well Scope Document – a very high level summary (supported by whatever

information is available at the time including a preliminary PPFG plot and formation

tops) produced as soon as a prospect that has the potential to be drilled is identified.

This is used primarily to ensure rig capacity and long lead items are available, but also

to provide some initial budgeting costs, etc. for the well. It is usually prepared (or at

least should be) around a year before the well is drilled.

2) The Subsurface Well Proposal – this is the main “information document” provided by

the subsurface / operations geology teams to allow well engineering to do some more

detailed well design work, and should include the finalised signed off PPFG prediction.

It is expected that this document is provided as early as possible, but as a minimum 4

months prior to spud. Any changes made after this date are subject to a MoC and could

have an impact of the spud date.

3) The Geological Well Programme – this is the final document that is produced (usually

by the operations geology department) to be used by the operations team during the

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well. It contains additional (mainly geologically focussed) information as well as the

requirements for the mudloggers, data gatherers, etc. at the wellsite.

This presentation will address the key components of this process and how well engineering

are able handle some of the uncertainties that are present with the proposed well. In a nutshell,

this is a presentation of what well engineers want.

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NOTES

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Can We Drill There? Well Locations and Top-Hole Drilling Hazards Francis Buckley, LR Senergy

Introduction

Shallow hazard analyses and site clearance studies are often the least regarded aspects of a

well drilling project, though they have the potential to stop such a project before the rig gets

anyway near the site. Seabed and top-hole conditions may be such that a well is essentially

un-drillable, but without precise and targeted interpretation of site survey data, followed by

careful reporting and thoroughly reasoned risk analysis, some hazards to well operations may

never be considered until it is too late to take mitigating measures. This presentation takes the

form of two imagined case studies using real examples from both shallow and deep water

drilling projects around the world.

Shallow Water Well

Operator A has a site survey seismic dataset acquired nine years ago for a series of wells

drilled from a subsea template near the site centre and they would now like to use the same

data to drill an additional well a short way from the template and lay a pipeline and umbilical

back to a subsea manifold. Unfortunately the new location is covered by HR data with only

100m line spacing and proposed relief wells are on the very edge of coverage. The HR data,

though within the 10 year limit recommended by OGP guidelines, are considered to be

effectively redundant for shallow gas interpretation as subsequent drilling may have induced

shallow gas migration. A geotechnical borehole lies within a few km of the new location, but

the jack-up rig contracted to drill the well will require new boreholes on each of the three spud-

can locations and the latest seabed clearance data is much older than the 12 month limit

recommended by the OGP.

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Figure 1. Seismic sections illustrating: a) proposed deviated well path; drilling induced seismic anomalies; b) shallow anomalies as a hazard to borehole operations; c) problematic conductor installation conditions

A new survey is carried out including 25m HR2D line spacing around proposed well locations,

new sub-bottom and seabed data encompassing the anchor spread for semi-submersible rigs

that could potentially be installed on relief well locations and a geotechnical borehole

programme is also organised.

The site survey interpretation reveals a seismic anomaly pattern somewhat more extensive

than was interpreted in the original survey, including some very shallow anomalous events

close to location and a ‘stacked’ pattern of anomalous events centred on the existing well

cluster. Some deeper anomalies on the proposed location are potentially problematic and an

anomaly at approximately 900ms TWT, though lying further than 100m from the proposed

location, lies much closer to the deviated wellpath that ‘kicks-off’ at 600ms TWT and is planned

as open hole to 1000ms TWT.

Shallow geology on location is not considered suitable for jack-up installation as it lies on the

flank of a steep infilled channel so a new location is proposed avoiding the channel and the

seismic anomalies. This work is carried out just in time as the geotechnical borehole vessel is

mobilising to carry out the borehole survey. Some last-minute location optimisation and

reporting is required to give the borehole vessel assurances that there are no shallow gas

issues within borehole depth.

The borehole programme turns out to be a lengthy process as, though the previous site survey

interpretation states that shallow soils, belonging to the ‘Forth Fm.’ should consist of soft clays

and silts, as documented in available publications, soils on site are actually a glacially

tectonised and highly disordered assemblage of hard clays, dense sands and cobbles. After

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several new locations have been tested, involving numerous boreholes and iterative analyses

of shallow geological and seismic anomaly interpretations, a final set of three spud-can

penetration analyses are pronounced to be satisfactory and the jack-up installation and final

drilling locations are agreed and reporting is finalised ready for inclusion in the wellplan

documents.

Deep Water Well

Meanwhile, off the coast of West Africa, Operator B intends to drill a wildcat well in 1500m of

water, with a recently acquired 3D volume for guidance. Water depths, time-frame and

budgetary considerations all preclude any new site survey data acquisition. A quick appraisal

shows that, though the data is high quality with a well defined seabed and minimal acquisition

artefacts, the 25m bin spacing, 4ms sampling and 50Hz dominant frequency content all fall

short of OGP recommended guidelines (12.5m, 2ms, 60Hz). A subset of the data,

encompassing a range of potential drilling locations and relief well locations and including a

1km migration envelope, is therefore selected for re-processing using a short-offset (SO3D)

algorithm by a seismic processing contractor.

Meanwhile a regional study is carried out on the full-stack 3D data which identifies a range of

hazards both at seabed and in the top-hole section that could all impact on the well location.

Recent seabed instability is apparent and pockmarking and seabed moats all indicate deeper

seated causes. Conductor-depth geology in particular appears to be problematic, however a

slot becomes available on a geotechnical vessel, which is just completing a contract a few

hundred km down the coast, and a series of 40m seabed cores are acquired that inform both

geotechnical considerations for conductor analysis and geochemical studies for regional

exploration purposes.

A Bottom Simulating Reflector (BSR) is identified on the seismic data, slightly deeper in the

section, and is associated with mud volcanism, reef build-ups and pockmarking in neighbouring

blocks. However the example on site appears to be normal polarity (compared to seabed) and

so is interpreted to be an Opal A to Opal CT diagenetic boundary. A core acquired several

hundred km away, as part of the Deep Sea Drilling Programme, encountered a chert layer at a

similar BSR, and an offset well only 50km away drilled the interval without problems, though a

wireline response was noted.

Deeper hazards include a buried canyon system, several levels of seismic anomalies, fault

swarms over salt domes, debris flow deposits and palaeo-mud volcanoes.

The SO3D data having become available and a drilling location having been specified, a

location-specific drilling hazards study can be carried out, including the results of the recent

coring programme, the 50km distant offset well and some of the results from the operator’s

sub-surface team. The increased frequency content and tighter bin spacing has resulted in

greater vertical and lateral resolution, conforming to OGP guidelines and boosting confidence

in interpretations and risk analyses.

Seabed gradients close to the location sometimes exceed 10°, but careful surface rig

positioning and location of the drill string at seabed will ensure that the actual drilled location

remains in a benign environment. The coring programme has fed into a conductor

emplacement analysis resulting in some recommendations for conductor design and

emplacement from the geotechnical engineering team and the worst of the seabed instability

areas have been avoided.

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Although the BSR has been shown to be relatively benign and the risk of gas hydrates is low,

some deeper palaeo-mud volcano or fluid migration pipes have been identified that are

associated with a series of amplitude anomalies that have been carefully delineated, but the

risk of gas is debateable. Fortunately the original 3D volume included Near, Mid and Far angle

stacks and these are used to produce a series of AVO products, including sections, volumetric

extractions and cross-plots that confirm the High Risk category of one particular anomaly close

to location. A revised location is proposed, the risk analysis re-iterated and the new location

confirmed.

A number of other techniques are employed including the production of dip, similarity and

curvature volumes to image turbidite channels, faults and other discontinuities, frequency

decomposition volumes to generate RGB images and the combination of Near, Mid and Far

volumes to produce alternative RGB images for horizontal facies interpretation. Final reporting

results in a series of products for inclusion into the well planning procedures.

Figure 2. RGB blended image of frequency decomposed seabed reflection showing: a) slope failures; b) linear mud vents; c) seepage-induced authigenic carbonate reefs

Conclusions

Top-hole geology and geohazard acquisition and reporting are extremely important. If not

carried out correctly or in sufficient time it can result in expensive hold-ups, even more

expensive loss of rig-time or, at worst, truly disastrous consequences. Proper engagement of

all parties, including survey contractors, geohazard consultants, explorationists, operations

geologists and drillers will ensure that all perceived rig installation and top-hole drilling hazards

are interpreted, considered, properly risked and mitigated in advance of a rig arriving on

location.

References The International Association for Oil & Gas Producers’ Geomatics Committee, 2013. Guidelines for the conduct of offshore drilling hazard site surveys. OGP Report No. 373-I8-I, Version 1.2.

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Kicks and Their Significance in Pore Pressure Prediction Richard Swarbrick

1,2, Jack Lee

3 & Steve O’Connor

3

1Swarbrick GeoPressure Consultancy

2University of Durham

3Ikon GeoPressure, Durham

Kicks (fluid influxes into boreholes), whilst not an intended outcome during drilling operations,

are nevertheless valuable data points in pressure interpretations. In relation to pore pressure

prediction kick data can offer useful interpretation/calibration values of formation pressures for

reservoirs and/or other higher permeability rocks being drilled, including faults and open

fractures. Furthermore, they represent an instantaneous indication of underbalance

(comparison between the higher formation pressure and pressure exerted at that depth by the

weight of the borehole fluid). Kicks may occur during active drilling operations, when the

underbalance relates to the ECD mud pressure. However, statistics would suggest that kicks

are more common when there is no circulation of mud and often when the bit is “off bottom”.

Unexpectedly high pressures, in sufficiently permeable rocks being drilled to cause an influx,

can be the result of:

High reservoir pressure during deep drilling (e.g. shelf gas play in Tertiary deltas) where

conventional shale-based pressure prediction methods fail to deliver accurate results;

Reservoir pressures at the crest of tilted structures where lateral transfer leads to higher

overpressures in the reservoir than the surrounding shales (e.g. shallow water flows;

growth faults in Tertiary deltas such as Niger Delta);

Complexity in drilling severely drained reservoirs in association with high pressure

shales in which there may be hydraulically isolated reservoirs at high pressure (e.g.

South Caspian Sea; West Africa).

Thick, tight rocks such as shale and chalk, which yield little direct indication of pressure,

even while-drilling, in which there are rare, thin (e.g. sub-seismic) high-permeability

units and/or open fractures/faults (e.g. Central North Sea Chalk Group).

A global set of examples will be used to show that some kicks could have been avoided by

attention to pre-drill and real-time analysis of the pressure regime.

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Wednesday 26 November Session Two: Execution/Case Studies

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Managed Pressure Drilling through Mungo’s Salt Diapir

Thomas Bond, BP

Drilling around salt diapirs has long been a challenging practice – the structures’ unique

geology and high degrees of seismic uncertainty historically prompting operators to approach

these fields with caution. Typically diapir growth leads to a number of effects in the surrounding

rock including thinning and highly dipping formations, radial faults and fracturing, and severe

stress heterogeneity, all contributing to a complex subsurface environment. Mungo, part of the

Eastern Trough Area Project, is one such field where the impact on wells has ranged from non-

productive time to lost hole sections.

Factors such as those above have led BP to begin drilling through the stock of Mungo’s salt

diapir, emerging into the reservoir from underneath and avoiding hole instability in the

overburden. However this is not without its own trials, namely brine flows throughout the salt,

significant losses in the heavily fractured chalk overlaying the diapir, and interbedded shale

instability due to high inclination drilling down- dip in depleted reservoir sands.

For the upcoming third phase of Mungo development, BP will employ various dynamic

pressure drilling techniques to facilitate drilling three proposed subsurface targets. Installation

of a rotating control device and choke above the BOP stack offers the ability to hold back

pressure on the well during operations, and an associated coriolis meter and pump accurately

measure and manipulate flow. The system provides a near- constant bottomhole pressure

regime (often termed managed pressure drilling or MPD), allows enhanced kick detection and

confidence drilling ahead against continuing brine influx, and adds additional protection for the

rig in the event of total losses.

This presentation will outline the technology and methods and their potential to address

Mungo’s manifold technical challenges. Bottomhole pressure selection, well control

considerations, and operational planning in anticipation of 2015’s drilling campaign will be

discussed.

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Figures Courtesy Diana Cristancho

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Challenges and Uncertainties of Pore Pressure Predictions in High Velocity Over

Pressure Formations: An Alternative Vp/Vs Based Approach

Ajesh John, Cairn India

Estimation of accurate pore pressure is important for safe well planning and its cost effective

completion in regions where narrow pressure margins challenge the exploration opportunities.

Over pressures are commonly associated with under-compaction and/or unloading

mechanisms. Overpressures associated with under-compaction generally possess a direct

relationship between effective stress and velocity, whereas unloading related pressures do not

provide such direct indications from porosity trend. Pore pressure distribution and over

pressure mechanism (Miocene and below) in Ravva field, from east coast of India is a classic

example of unloading in high velocity formation, making it difficult to resolve both the

magnitude and trend of pore pressures.

Vp/Vs ratios are analyzed from the drilled locations to understand the effects of lithology,

pressure and fluids on formation velocities (Fig.1). Vp/Vs trend analysis from the drilled

locations exhibits a distinct cutback across the overpressure regimes and corresponds to

excess pressure resulting from unloading mechanisms. Vp/Vs values across the high

pressured zones shows low values compared to normally pressured zones possibly due to the

presence of hydrocarbon and/or overpressures. A velocity correction factor of 0.83 - 0.78 is

resolved for over pressure zones by normalizing the Vp/Vs values across the normally

pressured formations (Fig.2). Pore pressure estimation using corrected velocity from Vp/Vs

analysis has shown high degree of accuracy on prediction trends (Fig.3).

Understanding pressure mechanisms and their role in Porosity-Effective stress relationship is

most crucial in pore pressure prediction estimation, particularly in complex geological and high

temperature regimes. Vp/Vs based pore pressure predictions are more effective and valid

approach in high velocity over pressure regimes where numerous factors can contribute

pressure generation and a direct effective stress-porosity relationship is distorted. However,

this method can only be used after validation with other parameters that could affect the Vp/Vs

trend.

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Wednesday 26 November Session Three: Execution/Case Studies

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How the Revised Extent of a Fault Tip on Re-Imaged Seismic Data Impacted the

Planning Of a 36 Well Programme

Paul Roylance, BP

The Clair field was discovered in 1977, 70km West of the Shetland Islands. Concerns over

achieving commercial flow rates in tight fractured Devonian rocks resulted in a 28 year stop-

start appraisal phase before Phase I was finally sanctioned and brought online in 2005.

In 2016 the phase II development, ‘Clair Ridge’, will increase production with the installation of

a new platform. A series of pre-drill wells were planned off an 8 well template at the Ridge

location in advance of the platform installation. These were drilled with the PBLJ semi-sub in

2012/13 prior to a full 36 slot template being overlain during the Platform jacket installation.

This presentation focuses on the impact a new seismic volume had when it arrived late in the

well planning process. The new data was interpreted to give a more accurate position of the

fault and show the large offset ‘Ridge Fault’ extended significantly shallower and potentially

closer laterally to the planned wells than previously mapped leaving a reduced offset. The

identified risks associated with drilling close to the fault included wellbore loss due to fault

reactivation and fluid losses into a rubble zone.

These hazards might have derailed the whole programme because the template could not be

moved due to the narrow positioning window confined by sea bed topography and boulder

presence. The only option remaining was to assess the risks, and agree mitigation actions to

be embedded in the predrill well plans. The initial predrill template wells were to be assessed,

but the full 36 wells (already planned) would each need reassessment.

To overcome this required input from many disciplines within BP and support from the other co-

venturerers. This provides an excellent example of multidisciplinary team work to assess a late

emerging high impact risk and how it was successfully managed.

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Integrated Well Planning and Operations

Tom Sinclair and Jordan Graham, BG Group

In frontier exploration basins, determining pore pressure and stresses for well planning and

operations is often challenging where the primary objective is to drill in a safe and cost efficient

manner. Offset wells can provide a very good calibration and understanding of the basin from a

geological and stress field perspective. However, exploration wells are always pushing the

limits of previous offset wells where deeper plays are now targeted, than the wells used for

calibration of the overburden in the basin. The successful and safe drilling of wells in these

increasingly challenging environments requires a collaborative approach to the well delivery

process from planning through operations and to post drill learning. Reducing uncertainty in

pore pressure prediction and geomechanical understanding is crucial to the safe and efficient

drilling of exploration wells.

This paper gives an overview of challenges encountered during recent BG operated frontier

exploration wells where drilling conditions provided a unique challenge for real time pore

pressure prediction, data acquisition, seismic uncertainty and well tie and stress calibration.

Case study examples include differing timescale examples of managing highlighted risks and

the planning and execution of an efficient data acquisition campaign reducing uncertainty and

contributing to successful operations.

During the operations, the pore pressure and geomechanics specialists are based in the ICE

(Integrated Collaborative Environment) centre providing technical support to the asset. The

operations geologist based in country is the key focal point for any interaction and support

which ensures an effective operational process and allows for a ‘One Team’ philosophy to be

applied. This enables collaborative decisions on pore pressure, stress calibration and

operational strategy to be made, which draws upon the combined knowledge and skill of all

involved to deliver success in a challenging environment.

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Geological Operations: Integration of Data. Case History in Jaguar-1 Well (Guyana)

Teresa Polo, Johan Lall, Allan Kean, David Garcia, Karl Perez, Eduardo Altamira, Vyanne Rojas,

Repsol Exploración, The Woodlands, Texas, USA

Planning and executing a well requires the work of different specialties (G&G, Drilling, HSE,

Logistics, Purchasing and Contracts, etc.), and the integration of information is a key value to

understanding the Geological and Drilling performance in a well. In the case of Jaguar-1, the

well was planned to reach TD at 21,435ft. However, the unexpected overpressure found below

14,000ft forced the Operator to abandon the well at 15,998ft, after reaching a point in the well

where the pressure design limits for safe operations prevented further drilling to the main

objective.

While drilling the intermediate sections, the gas shows started to increase giving evidence of a

higher than expected pore pressure regime whereas the indirect methods to calculate pore

pressure (resistivity, sonic, d exponent) showed lower values. The poor information from offset

wells in new frontier areas makes Pore Pressure calibration difficult to predict as the NCT is

made with no inputs of chemical compaction models.

However, the integration of both Drilling and Geological data permitted recovery of samples of

light oil in very thin sands that helped to understand the pressure regime, the geological model

and the drilling performance of the well. The result was crucial to taking the final decision for

abandonment, reducing the risk of the operation and helping to plan forecasted operations in

the basin.

The integration of data is done by the Geological Operations team, which is responsible for

data acquisition in a safe manner. The ability to communicate and interact between the

different teams is mandatory for creating a good understanding of well conditions and

delivering a well with a safe and complete evaluation program.

Figure 1 Location map for Jaguar-1 well

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Figure 2 Prognosed versus Actual pore pressure regime for Jaguar-1 well

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Wednesday 26 November Session Four: Execution/Case Studies

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While Drilling Shale Dispersion Tests Improves Drilling Performance Kaleem Anwar, BP Iraq SPU

Rumaila is one of the largest producing field in the world. The total concession area is ~ 80 x

20 sqkm. The field was discovered by BP in 1953. The field is operated by the Rumaila

Operating Organization (ROO), a Technical Services Contract between BP (operator), Petro

China and the Southern Oil Company.

Figure 1 Rumaila concession map

About 1000 predominantly vertical wells have been drilled on the field and several of these

have failed for various reasons, it was decided to re-enter some of these wells and side-track

from the existing mother bore. There were two main aims of the side-track campaign firstly to

bring a well back on line at a lower cost than drilling and hooking up a new well and secondly

to gather information to aid future high angle and horizontal well campaigns.

The first well of the side-track campaign was spudded in August 2011 at a planned angle of

45º. The well took 154 days versus planned 29 days. The well had to be drilled 4 times (figure

2) to get liner down to the required depth

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.

Figure 2 well days vs depth

While drilling the first sidetrack higher than normal volumes of cavings were recorded, a

selection of these cavings was sent back to bp in the UK for fast track analysis. The dispersion

tests (Figure 3) showed that the KCl Polyplus (10ppb) mud that was being used reacted with

the shales.

Figure 3 Dispersion test

The mud rheology was adjusted to reflect these results and the well was successfully

completed.

As a result of this all the shales were cored and the analysis (shale XRD and CEC and

Dispersion tests) done on the shales from different formations has enabled ROO to optimise

the mud which has resulted in a better quality bore holes.

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The Tolmount Field – Continual Integrated Learning for Geoscientists and Engineers Alan Grant and Richard Smout, Eon E&P, Aberdeen

Block 42 Southern North Sea Tolmount Field is the location of drilling and geoscience

perseverance and tenacity.

Despite the number of wells drilled in the Southern North Sea, some blocks still present

significant geological and drilling problems. This presentation charts the recent history from

initial unsuccessful attempts to drill exploration wells on Tolmount, through changes in design

and well location due to the geo-hazards encountered, resulting in a successful exploration

well. Further changes were subsequently made to well location and plan before the successful

2013 appraisal well which still managed to give us a number of surprises.

Between 2008 and 2013 four wells and two sidetracks have been drilled from four separate

locations on the Tolmount structure; each well having significant issues. The first well drilled by

Dana Petroleum in 2008, well 42/28d-10, failed due to mechanical rig problems. In the summer

of 2010 Eon Ruhrgas drilled and abandoned well 42/28d-11 and then 11z without reaching the

target, due to significant borehole collapse, mainly at Lias level. The route cause was large

scale faulting.

In September 2011, after extensive re-planning, Eon Ruhrgas drilled well 42/28d-12, located

315m to the SE of the 42/28d-11 and successfully reached the reservoir. The highly

problematic Lias section and large scale faulting throughout the post-Zechstein overburden

could not be avoided but risk mitigation involved a dedicated casing string to isolate this

interval, drilling and casing in a seamless operation and specifically chosen mud weight to

avoid borehole collapse and losses. Minor caving was observed but casing was landed without

incident. Additionally, after stuck pipe in the Zechstein salt section, the well took a high

pressure brine kick in the Platten Dolomite. With a drilling liner set higher than planned across

the Zechstein, a longer reservoir section with a significantly higher mud weight than planned

was drilled, cored and tested with negligible problems.

In the summer of 2013 well 42/28d-13 was drilled by E.ON E&P UK. Initially planned from the

same surface location as the previous exploration well, as part of a risk mitigation exercise it

was decided to drill a standalone well which reduced the probability of taking losses and/or

borehole collapse when crossing the large scale faults. Additionally the well would be drilled

through a relatively benign area of Platten Dolomite. This resulted in a fish-hook well path.

Drilling the problematic Lias was limited to 10 deg. and no significant hole problems were

encountered with it or with crossing any of the overburden large scale faults. This was seen as

a success for well planning tenacity. The Zechstein was drilled at a 15 deg sail angle. As

anticipated, a high pressure brine kick was taken, though not at the depth expected, and this

was circulated out and the influx bled down before drilling the remainder of the section with

further changes being made to the mud weight and the cement slurry design. The 6in section,

with a fairly challenging directional profile, required controlled ROP through the more friable

sand intervals in order to get the build necessary to enter the reservoir section at 55 deg to

maximise the chance of encountering the GWC. The well exceeded the probability range

associated with the GWC, necessitating an unplanned side-track. Although successfully drilled

with an even more challenging directional profile, the well crossed four faults before TD,

illustrating a more complex structural puzzle than had been anticipated.

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Well planning has continued with the development and appraisal wells in order to successfully

develop the field. The success of the development will rely on expert well planning from drilling

and subsurface.

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Thursday 27 November

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Keynote Speaker: Where Are We Going As Geologists Within The Industry? Malcolm Brown, BG Group

What does an Operations’ Geologist do and what are the key attributes? Has the role changed

significantly during the last 35 years? Although technology has advanced enormously, I would

suggest the key skills have not changed.

For an Operations Geologist to work effectively during the various phases of the life cycle of a

well they need to be an integrator between the subsurface and drilling teams, with an

appreciation of the risks and relevant technical mitigations. Communication is key, both within

the team, but also to senior management, occasionally good news! There is also a key role in

HSSE, ensuring safe drilling practices are adopted from well planning to execution.

The appeal at the sharp end of the business is not only pushing the boundaries in terms of

technology, but being able to see the conceptual subsurface models ground truthed. These are

the areas that have really fascinated me and what excite me are the new challenges we are

facing in our industry.

The boundaries continue to be pushed in terms of difficult and remote operations. Exploration

and production is now taking place in deeper water, >2000m is no longer exceptional and

tough conditions of high pressure (15,000psi) and temperature (200deg C) are achievable. We

have seen a significant shift into the world of unconventional plays and the challenges facing

Arctic drilling campaigns. The new technological enablers in the recent past have included

steerable BHA’s and Managed Pressure Drilling to navigate through narrow pore pressure

fracture pressure window. Where are the next frontiers and what competencies do we require

from the next generation of operations geologists to meet the challenges?

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Thursday 27 November Session Five: Technology

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Introduction to the Managed Pressure Drilling Process with Case Study Feedback on Real Experiences in the Field Carl Hills, Total

Introduction

Managed pressure drilling is an adaptive process whereby the well is converted into a closed

loop system. By sealing the top of the well through the use of a rotating circulation device

(RCD) at surface above the BOP, losses and gains within the wellbore can be more closely

monitored giving much tighter control of well parameters. With the closed system, flows can be

very accurately measured by connecting a high precision mass flow meter and automated

choke to the outlet of the RCD. Drilling is conducted in the normal way but all returns are

directed via the flow meter and choke to the mud pits with the option of directing the flow via

the MGS or a dedicated drilling MGS. The managed pressure drilling system relies on the

concept of flow in versus flow out. If the flow out does not equal flow in, then there is a problem

that needs investigation. Figure 1 below outlines the basic setup.

Figure 1. the layout of the MPD closed loop system.

Drilling difficult wells

As operators strive to drill deeper, more complex wells in more remote fields with limited offset

data the pressure regimes become more complex. Typically on HPHT wells a pressure ramp

occurs and the pore and fracture gradients become distorted resulting in a narrowing of the gap

between pore and fracture gradient compared to a more typical normally pressured well with

limited temperature effects. Alternatively, operators wish to undertake well campaigns in little

known areas and simply have lower confidence in the likely pressure regime. These factors

alone have presented significant challenges to well engineers to the extent that some wells are

literally ‘undrillable’ through normal atmospheric drilling methods whilst adopting typical

industry accepted design safety factors ie trip margin, kick tolerance etc

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These types of factors have accelerated the uptake of closed loop drilling technologies. Initially,

the focus was upon simply drilling the well. However, as both operators and service providers

have gained more experience, the additional benefits of managed pressure methods have

become apparent.

Typical benefits

Speed and accuracy of identifying well events

Safety and cost considerations

Significantly reduced unplanned well control events and subsequent recovery

Ability to differentiate ballooning compared to a suspected kick

Variety of well phenomenon: differential sticking, borehole stability, losses

The ability to ascertain true inflow and leak off gradients dynamically while drilling

The importance of data

The last factor mentioned is of particular interest to subsurface professionals. Whilst analyst

can develop offset data and make inferences for low, medium and high cases for pore and

fracture gradient, the fact remains that we often do not know what we will get until we drill the

well. This is particularly the case when drilling in remote areas where offset data may be one

well that was drilled 30 years ago.

The presentation supporting this abstract will outline the equipment and considerations

required to undertake managed pressure drilling. It will discuss the challenges and lessons

learned and examples will be given from recent MPD campaigns of the flexibility of the system

and its ability to provide subsurface professionals with additional real well pressure data while

drilling through the use of dynamic leak off and inflow data while drilling.

The MPD concept downhole

Figure 2 below shows the likely scenario when trying to drill a narrow margin well with a

conventional mud gradient to balance pore plus a safety factor and a trip margin. In the

illustration we show the mud gradient chosen above pore as expected for the whole depth of

the well with the various safety factors. Due to the tight window between pore and fracture

gradient we can see that, at points, even the static mud gradient is almost exceeding the

expected fracture gradient and we are likely to experience losses. Once the losses are

propagated, we may never cure the losses. If we now consider the effect of ECD on this case

when we switch on the mud pumps, we see that effective mud weight far exceeds our expected

fracture gradient. Hence the well is technically ‘undrillable’.

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Figure 2. A typical conventional drilling mud regime to drill a narrow margin well

In figure 3 below we see an example of one method of designing the well using a closed loop

system. In this example we show that the actual static mud weight is below expected pore

pressure. However, as we show the effect of switching on the mud pumps (the green line) we

see that the dynamic effective mud gradient is within the pore and fracture gradient and the

well is technically drillable without breaching the fracture gradient. As the well is a closed

system, we can trap a pre-planned amount of surface pressure to augment the static mud

gradient that is effectively below pore pressure. At or near the drilling depth, the well is kept in

balance due to this trapped pressure. This is the closed loop or managed pressure concept in

one of its simplest forms. In reality, commencing a drilling campaign statically underbalanced is

commonly out with a given operator’s pressure control policy. However, for many campaigns,

we can simply reduce the drilling mud density by the amount of any safety factors traditionally

applied to mud weight for conventional drilling. By doing this we can often start with a lower

statically balanced mud weight and achieve a much more acceptable ECD through the MPD

process yet still work within accepted company policies. As operators gain more confidence in

the closed loop concept and the offshore team has undergone a suitable learning process, the

team often wish to experiment with a statically underbalanced mud weight on subsequent well

campaigns.

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Figure 3 Using a closed loop system to walk the line between pore and frac: using ECD to provide BHP with the well closed on connections

Conclusions

The basic building blocks for closed loop drilling have been available for some 20 years.

However, as wells have become more difficult to drill and operators seek a tighter control over

wellbore pressures and unplanned events, the closed loop process is becoming more

attractive. Typical equipment spreads for managed pressure drilling are significantly less than

those of say under balanced drilling as the design does not plan for hydrocarbon production at

surface and the basic concept is not to ‘flow the well’. Additionally, no gas compression,

secondary compression, sophisticated separation equipment are required. Hence the MPD

footprint is surprisingly small and easy to understand. Closed loop drilling systems are in their

infancy and already, the technique is enjoying and unprecedented level of demand and an

acceptance due mainly perhaps to its relative simplicity.

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Permeability Constrained Pore Pressure Observations from the Chalk Group, UKCS Richard Hood, Nick Pierpoint and Simon Phipps

*, BG Group

*Previously BG Group

There are distinct elements to modelling pore pressure in the Central North Sea – velocity

modelling is the technique adopted for the Tertiary claystone. This is in contrast to older

sediments of the Cretaceous, Jurassic and Triassic, where the use of offset data in the form of

reservoir pressures and drilling events are the primary datasets used to constrain the pressure

model. However one of the main challenges is pore pressure prediction in the low permeability

Chalk Group. Analysis of log data does not provide a proxy for pore pressure in the carbonate,

and a deterministic approach was adopted.

This presentation and case study aims to describe the assessment of pore pressure and

Geohazards on a North Sea Central Graben exploration well and provide evidence which will

feed back into our future thinking. Gas data unveiled an underlying trend whereby permeability

constrained units may have led to a well control situation based on offset well data. Are the low

permeability units hydrocarbon bearing and where is the onset of the pore pressure transition

zone? The case study presented illustrates the impact of low permeability hydrocarbon bearing

zones on well abandonment.

The drilling experience will be detailed, post well study unveiled, and the results shared.

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Thursday 27 November Session Six: Technology

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Deciphering the Formation Fluid Signature in Real-Time Using a New Oil Based Mud Fingerprinting Technique for Mass Spectrometry M.J. Reitsma, C.J. Harlow, W. Davies, HRH Geology, 19 Silverburn Place, Aberdeen AB23 8EG, UK

Whether drilling an exploration, appraisal or development well, advanced mud gas data can

supply crucial real-time information. It complements LWD measurements by e.g. indicating the

presence of producible hydrocarbons, proximity to pay, depths of original and moved fluid

contacts and compartmentalization. This aids quick decision making at the rig but the data also

provides detailed understanding of the reservoir when analysed in depth in town.

Formation hydrocarbons are extracted in gas or vapour form from the drilling fluid as it reaches

the surface. However, in wells drilled with oil based mud (OBM) the analytical system will also

pick up the volatile organic compounds released by the drilling fluid itself. In other words, the

OBM vapours obscure the true formation gas signature and need to be corrected for (figure).

Figure: Simplified, the OBM discriminator searches an OBM background scan (blue mass spectrum) that

matches on key OBM peaks with the formation scan (red) and then subtracts the former from the latter

to obtain the formation fluid signature. This sample contains 3712ppm methane, 615ppm ethane,

317ppm propane, 252ppm butane, 115ppm pentane, 38ppm hexane, 13ppm heptane, 16ppm

cyclopentane, 4ppm cyclohexane, 3ppm benzene.

The precise OBM vapour fingerprint is highly temperature dependant and varies from product

to product and even batch to batch. We have developed algorithms that correct mass

spectrometry derived data for this variable OBM interference. The OBM is fingerprinted during

a wellsite test and/or while drilling a dry gas zone before penetrating the reservoir. This data is

developed into a dynamic OBM pattern that can be applied to the mud gas data in real time.

Additional analysis of post bottoms up circulation of OBM is used to detect time induced

changes in the drilling fluid or to reveal potential recycling of formation gas.

Application on multiple rigs in the North Sea has demonstrated the effectiveness of the method,

even when applied to hydrocarbon poor reservoirs.

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Well Operations Centres - The Next Step.

Mike Jackson ICE Manager, BG Group, 100 TVP, Reading, RG6 1PT.

This presentation describes the changing and dynamic roll within a Wells Operations Centre.

In BG, an Operations Centre (ICE – Interactive Collaboration Environment) has been in place

in TVP since 2009. The ICE was established with a cross functional team to provide decision

support to BG’s Operating Assets involved in delivering critical wells. Following the occurrence

of two significant events, Senior Management changed the focus of the ICE. These two events

were the Macondo Blow Out and challenging delays on the HTHP BG Jackdaw wells. This led

to the ICE being reconfigured to accommodate a 24/7 monitoring capability of all BG operated

(and some non-operated) wells. This provided additional support and overview of operations

allowing direct technical support to be offered the well-site team.

From a subsurface perspective, resources in the pore pressure and geo-mechanics arena were

enhanced significantly along with improved Well Engineering capability. A team of 17 people

are based in the ICE centre in TVP Reading providing support to operated and non-operated

Assets around the globe. The ICE is able to utilise BG Global resources efficiently with multi-

disciplinary experts able to provide support to several assets simultaneously. This support is

available throughout the planning, assurance and operational phases and incorporates the key

element of sharing and implementing lessons learnt.

This central hub is utilised by the organisation as a conduit for flow of data and operational

information in and out of BG head office to ensure consistent messaging and reporting and

grants the ability access a greater technical support. It also provides an excellent training

environment for BG graduate trainees and

It should be stressed that the Asset teams retain full operational control and responsibility. To

ensure this works in a collaborative manner, robust communication protocols are in place

which are agreed to in advance of spud which detail how interactions are to be made and with

whom. This is adhered to and respected. The whole basis of a successful ICE is trust and

communication. The ICE team must be viewed as part of the Asset teams and be focussed on

supporting the Asset teams in their delivery.

What is the next step – currently we are supporting the Kenyan Asset as they operate a remote

drilling operation from Reading. By utilising the ICE communication and collaboration tools we

are able to improve the ability of the Reading based team to interact with the operating site.

More to come on this!

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“What Did Those Micropalaeontologists Ever Do For Us?”

Haydon Bailey, Network Stratigraphic Consulting Ltd.

To paraphrase Monty Python just a little..... “What did those Micropalaeontologists ever do for

us?” “well there was the hot shot analyses that gave us the age of our reservoir, and there was

that wellsite “geosteering” job that enhanced all that recovery and we were lucky when that

chap did the geostopping job just above the BCU”.

“Okay, so I grant you the “hot shots”, the geosteering and the geostopping, but really, what did

the micropalaeontologists ever do for us?”

“and the guy who helped calibrate a whole load of seismic for us.....”

“okay I’ll give you that one”

“and there was his mate who sorted out all that palaeoenvironmental data so that we could

work out that facies play”.

“Okay, I give up; so the anorak who showed up on the rig with that black box and looked at a

few samples when we TD’d the well did actually do some work before we packed him off

again?”

“Well, we won’t be seeing him again; I heard he’s retired and he was the last one working in the

North Sea; all the others have gone to get much better day rates in the GoM.”

Obviously a fictional scenario, but one that’s already come close to reality when we stopped

training micropalaeontologists in the UK in 2008. It’s easy to take a specialist for granted when

there’s always been a number of them available, all competing and keeping prices low; but

demography has a habit of creeping up from behind as we start to realise it when Jurassic

palynologists or Chalk nannoplankton specialists just aren’t there anymore.

How do you put a value on someone who’s trained for six or seven years and then worked in

industry for another thirty? Perhaps we should try, because that’s when you recognise the vital

importance of training the next generation.

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Highlighting the Importance of Teaching Operations Geology: Both at Msc Level and as Part of Continuing Professional Development Programmes.

Christine Telford

1, Stuart Archer

2 & Kim Watson

3

1CTC GEO LTD

2University of Aberdeen

3GDFSuez

Despite having graduate level entry requirements, mudlogging, wellsite and operations geology

have historically been regarded within the industry as a lowly undertaking and paid accordingly.

Highlighting the importance of these careers to fledgling geoscientists during teaching and

training is one way to change the beliefs of the next generation of geoscientists who can in turn

educate the wider industry. In addition to highlighting the importance of these roles in a rig

safety context, teaching can also reveal the criticality of good operational understanding in

other areas such as data acquisition decisions, data quality, real time decision making and

early interpretation.

The skills required for wellsite and operations geologists were traditionally acquired while

working on the job (i.e. at the wellsite). The conventional progression from mudlogger to

wellsite geologist to operations geologist ensured that skills learned were honed over many

years’ experience leading to, usually, a high degree of competency and a steady stream of

skilled operations geologists to meet the needs of the E&P industry. However as well design

gets more complex and execution more challenging, many companies have now realised the

value of operationally-experienced geoscientists and now have an urgent requirement to build

capacity in this area.

Transferring practical skills in a classroom environment is difficult and with reductions in

opportunities to learn at the wellsite (often due to restrictions on bed space) a new approach is

required. Progressive teaching and training techniques go beyond traditional classroom

learning and places a strong emphasis on learning by doing. Although classroom teaching

cannot create practitioners, if the subject matter is creatively taught through role play and using

real data then valuable insight into the world of geological and drilling operations can be

transferred.

Using simulation concepts where wells are ‘drilled on paper’ allows tutors to interact with

students in a different way. Providing examples of the real life pressures of operations decision

making in the safe environment of the classroom gives the students operational awareness.

This more dynamic teaching method has even inspired some to make operations geology a

career path of choice!

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Shell Canada’s Field Rotation in Operations Geology (FROG) Program – Building Competence in Operations Geologists through Hands-On Rig Site Experience and Vetting This Competence by Multi-Disciplinary Assessment Brad Powell, Philip Benham, Morgan Wittstock, Julia Jackson, Royal Dutch Shell

Recognizing the rapidly changing demography of office staff towards younger professionals

with a noted lack of field experience, the FROG program was initially developed in Shell

Canada to be a focussed assignment designed to provide real time rig site experience to the

junior geologists. This field assignment develops operations geologist competencies in many

areas, including:

1) Operational familiarity

2) Roles of wellsite geologist & mudlogger

3) Intrinsic understanding of “Where the data comes from, how it’s generated, and how it comes together.” Enhanced ability to identify sources of error and QC of data.

4) Lines of Communication

5) Sociology of rig vs. office

6) HSSE procedures, reporting, hazard identification - but more importantly how geologist’s decisions affect field operations from a safety perspective.

The field rotation is intended to be a 2-4 month term consisting of 2 week “hitches”. The

participant is given a Competency Matrix and Task Tracker against which they are assessed

weekly. Competencies acquired over the field assignment are formally documented with

examples. Assessors may probe deeper on specific topics to ensure depth of understanding

and also assign tasks to perform on the next “hitch”

A pair of senior staff is identified to be assessors during the FROG assignment. One is to be a

Senior Operations Geologist with extensive field/wellsite geology experience, and the other is

an HSSE Lead. Final competency assessment is vetted by the Geology Discipline Lead.

Prior to field rotation, participants are to complete mandated safety training including H2S

Alive, First Aid, Proactive Driving, and rigsite orientation courses. All participants will be

outfitted with personalized PPE. A mandatory 3-day FROG/HSSE classroom orientation

course is also required. It is further expected that the participant would get a solid grounding

from the Project team around the asset geology, critical risks, well prognosis and maps for the

wells they will be sitting. It’s recommended that the participant experience two or more assets

to provide sufficient diversity of operations and geological experience.

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BP’s Accelerated Development Programme for Operations Geology

Tim Herrett1 and Kirstin McBeath

2

1 Tim Herrett Ltd 2 BP Iraq NV

BP’s Accelerated Development Programme (ADP) for Operations Geology was initiated in

2009 and since then over 50 existing employees and new hires have been inducted through 4

cadres. They have all participated in what is a structured combination of taught courses,

integrated simulations, practical (wellsite) experience, technical and personal leadership

coaching and positioned in targeted development roles throughout the world.

The programme was designed as a concept when BP realised that Operations Geologists in

New Wells Delivery were in short supply. The intent of the programme is to rapidly develop

and build capability and competency in well planning and operations geology to restore the

discipline as a key job family in BP and systematically balance the demographic challenge.

The programme has considerably

enhanced the development of the

participants both technically and

behaviourally.

Undertaking targeted on-the-job and

wellsite development opportunities

has allowed ADP Operations

Geologists to be deployed to regions

around the world where additional

assistance has been required,

benefiting the New Wells Delivery

Function, the regions, projects, teams

and individuals.

It is envisaged that the programme will continue with new cadres being introduced every 2

years or so for continuity and succession planning. As well as building a certain level of

technical competency and gaining valuable knowledge and experience, several ADP

participants have moved into leadership roles and some early participants are becoming

involved in the training and coaching of later cadres; transferring and sharing knowledge

throughout the global Well Planning and Operations Geology community.

This presentation will outline the structure of the Operations Geology ADP and the key

elements that make it a success from: (i) An instructor’s perspective, and; (ii) A current ADP

participant, who will each discuss the role of the programme components and tools in

facilitating the accelerated development of individuals, share some of the opportunities that

ADP participants have been given and discuss the value this has brought to the New Wells

Delivery Function and our projects around the world.

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Thursday 30 October Session Eight: Competence

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Managing Professional Competence in Operations Geology

Colin Higgins, OMV Exploration & Production GmbH., Trabrennstrasse 6-8, 1020 Vienna, Austria.

Managing Professional Competence has proved notoriously difficult since Operations Geology

emerged as a box on Organisational Charts in the late 1980s and early 1990s. Prior to this,

the responsibilities lay primarily with Staff Geologists (Exploration, Project or Development

Geologist) assigned to a well or series of wells. Globally the Operations Geology box on Org

Charts has been predominantly filled by Consultants.

The required competencies are potentially broader and more complex than any other branch of

geoscience.

We could say that we are a global community of mostly consultants/contract staff with a

relatively small number of full time staff (these are primarily in the Larger International Oil

Companies).

There are number of advantages to using consultants and contract staff in the role:

Costs can easily be recorded against the well AFEs and also shared under the JOA

Drilling activities are on a well by well or campaign basis and are of notoriously short

and mid term duration - use of consultants allows flexibility

Experience is highly valued and consultants can gain (and bring) a broad experience

relatively quickly.

We can try to hand pick consultants to closely match our specific needs eg UBD/MPD

experience, well placement specialists etc etc.

Unfortunately there are also distinct disadvantages of relying on Consultants:

Lack of continuity and building strong longer term teams

Loss of knowledge and learnings from the organisation

Pay a premium to compensate for flexibility

Little ability to fill knowledge or experience gaps (training and formal qualifications)

We often are unable to obtain the specialised experience for specific needs

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The Major IOCs and many NOCs and Independant Oil Companies have taken the initiative to

manage competency for all their technical staff including Operations Geology but perhaps with

such a broad skill set required we do not fit as neatly to the process as, say a Geophysical

'seat'. Some examples of how this is achieved in Operating Companies along with some ideas

are shared in the talk.

Our Consultants and Contact Staff that comprise the bulk of our Operations Geologists around

the world fall into 2 main categories: Sole Trading individuals and those working through a

'Specialist Provider of Operations Geology Consultants'. The number of these organisations

claiming to offer specialised contract staff, placements and consultants appears to be growing

daily. Should Operations Geology contracts be award to provide a service or to source suitable

individuals?

The question is then posed " How do body shops/consulting firms manage Professional

Competency for Operations Geologists?" Is there any professional development (technical

training, qualification tracking, attendance at conferences, team building, HSE leadership

courses etc etc). Is there a way to encourage Operations Geological (and WSG) Consulting

Groups to develop in house Professional Competency programs, with formal skills

development and tracking?

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Operations Geology: Establishing a Profession fit for the 21st Century

Tim Herrett1, Tim Watts

2 and Pat Spicer

2

1Tim Herrett Limited

2Consultant to Dana Petroleum

Operations Geology is a division of the science of Geology that serves the oil industry by

facilitating the safe and efficient planning and execution of well operations. It has evolved,

organically, with the industry, and served it well. However, it is the contention of the Authors

that the time has come to make Operations Geology a formal professional activity, with an

initial focus on the safety critical aspects of pore and fracture pressure (PPFG) forecasting,

monitoring and interpretation.

Why? A number of recent events in the industry have demonstrated the consequences of

failing to effectively manage PPFG issues. At present, there is no recognised industry wide

qualification or competency testing process to control who can present themselves as fit to be

an Operations Geologist. Raising professional standards clearly has the potential to help the

industry raise its safety and environmental protection game, by avoiding repeats, as well as

increase the efficiency of the industry.

Who will benefit? The professional will benefit by being able to demonstrate his or her

competency to add value to a client’s or employer’s business. Companies, regulators and

other interested parties will have a measure of assurance, currently lacking, that work done for

them can be trusted.

Operations Geology covers a multitude of activities crucial to well execution and there is a case

for a well rounded professional qualification. However, the author’s are proposing we should

focus on the safety critical parts first and grow from there.

The chicken and egg question – where and how to begin? Our paper discusses possible

sponsor organisations, training, competency assessment, models for certification, means of

developing competency and different levels of competency. The scope of work is the easy bit.

We will propose a means to begin the journey.

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Professional Titles with the Geological Society of London (GSL).

Bill Gaskarth, The Geological Society

Towards the end of the last century the GSL extended its role from simply being a Learned

Society to one which deals with both the Science and the Profession. In the early days of

offering professional titles through peer assessment the Society found that interest was largely

from sectors such as Engineering Geology and Hydrogeology where practitioners were

constantly working alongside professionally qualified Engineers (CEng). In other sectors such

as Oil and Gas, Mineral Exploration/Mining, Academia geologists were not clear on the need

for a professional qualification (Chartership- GGeol) either because it was not required for

career progression and/or training and competence was dealt with ‘in house’. However in this

increasingly litigious world more and more geologists are finding that peer assessed

competence, marked by a professional title, is becoming valuable and, in some instances, a

necessity. In the Oil and Gas sector geologists in smaller companies and consultancies

recognised this and acknowledged its value first, but now interest is growing throughout the

sector. The Society has effected a reciprocal recognition agreement with the AAPG and the

AIPG for CGeols who wish to work in the US. Similarly in the Minerals/Mining sector many are

finding that CGeol is a title required by the various Reserves and Resources Reporting

Standards in order for them to act as a Competent/Qualified Person (CP/QP) for reporting to

stock markets. In Academia the take up is still low but there is growing recognition that those

academics who teach on vocational courses perhaps should themselves have a professional

title. They are also looking to get their course accredited by the Society so that their graduates

can become Chartered at the earliest opportunity.

Generally the assurance that a Chartered Geologist (CGeol) has been peer-assessed for

competence, is bound by an enforceable Code of Conduct and is required to maintain their

competency through an audited CPD system, is recognised as valuable to both employers and

the general public.

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Poster Presentation

Abstracts

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Insights from the Kazakh Steppe

J. Raggatt, Senior Geologist, Tethys Petroleum.

Tethys’ current drilling operations are centred on the North Ustyurt basin in western

Kazakhstan where the company holds in excess of 10,000km2 of both exploration and

production contracts.

Central Asia country map – Tethys Country interests

With two principal geological plays being targeted, shallow gas in the Eocene at depth ranges

from 550-750m and deeper Cretaceous and Jurassic oil plays ranging from 2500 - 3500m, the

operations geology requirements are distinctly varied. Newly acquired wellsite data has given

additional insight into many aspects of the geological-hydrocarbon model.

This poster outlines two examples from recent wells drilled in 2014 and how this data acquired

by the operations geology and its subsequent analysis has proven critical in furthering the

technical understanding of a wide range of subsurface challenges – examples are from a

Cretaceous reservoir seal integrity review and also from oil samples recovered from shallow

cored reservoirs proving source rock age and migration pathways.

The principle resources employed to supervise and control the real-time operations geology

are experienced Tethys in-country geological staff, detailed remote monitoring from dual main

offices in London and Dubai and of course a planned rotation in and out of Kazakhstan to the

wellsite by senior geological experts.

The remote location of these operations requires substantial travel over several days from

London to the well site: several days of travel include multiple flights and a 550km drive

through the Kazakh desert.

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Tethys Kazakhstan desert well site operations – remote location drilling 2013

Tackling the sub-surface alone is not sufficient, other challenges exist: examples include the

environmental conditions with extremes of climate and temperature throughout the year, the

successful time-management of contractors to/from the well site across this remote location

and overcoming varied levels of language competency (English – Russian) between Kazakhs

and expatriate staff on rotation all requiring dedication to ensure a safe operational well is

drilled.

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Automatic Identification of Seismic Geobodies and its Application to Pore Pressure Analysis and Prediction

Rachael Hutson, James Selvage & Tom Sinclair – BG Group

An approach to scan large 3D seismic volumes for seismic anomalies has been developed by

Edgar and Selvage (2012) and extended to include pre-stack seismic by Selvage and Edgar

(2013). The approach produces geobodies by identifying anomalous amplitude behaviour in

the input volumes. Anomalous amplitude behaviour is identified by transforming the input

volume into either a flattened to Seabed or Wheeler domain. By then collecting local amplitude

samples from slices throughout the volume a domain dependent distribution of amplitudes can

be formed. Each amplitude sample in the volume can then be compared with its local

amplitude distribution to define how anomalous any particular amplitude is. Anomalies are

connected in 3D to define geobodies within the seismic volume.

This new approach to seismic interpretation has applications to pore pressure analysis and

prediction. The ability to highlight geobodies in 3D throughout the entire seismic volume can

allow for a fully comprehensive understanding of the basin’s plumbing and sand connectivity.

Lateral transfer of pressure through inclined sand bodies can create pressures at the crest

which are inflated compared to the pressure of the surrounding mudstones. This secondary

mechanism of overpressure cannot be predicated through seismic velocities, and therefore

creates a risk during drilling. The ability to predict which sands are connected to deeper or

more highly pressured areas of the basin and which might produce inflated pressures is

invaluable. Similarly, sands which may have dissipated pressure up-dip can also be identified.

This technique has been applied to a frontier tertiary basin, comprised of shale and deepwater

channel sands. Several wells drilled in this basin encountered pressures in the channel sands

which were above that of the background shale, predicted from seismic velocities. This new

approach, integrating traditional velocity based pore pressure prediction, with 3D geobody

mapping has allowed for potential pressure inflated sands to be identified and incorporated into

the pre-drill pore pressure prediction and well plan. It can also be used during operations, in

real-time look ahead modelling to help identify and risk upcoming sand bodies once a better

understanding of the pore pressure has been gained from LWD.

Figure 1. Geobodies extracted using the anomalous amplitude approach (left); overlain on PreSDM seismic (right). Pressure inflated inclined sand highlighted in red box.

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Re-Evaluating Shallow Geology in the Central North Sea

Francis Andrew Buckley, LR Senergy

Introduction

Characteristics of shallow formations may significantly impact on top-hole drilling strategies.

Shallow geology across the UKCS was mapped by the BGS in the 1980s and 1990’s, however

recent advances in seismic techniques are revealing new aspects of shallow geology in the

area.

Data

Seismic data have been used to map stratigraphic units and textures across part of UK Quad

30, using seismic attribute and geomorphological methodologies to characterise shallow

geological units. Lithological control is provided by geotechnical boreholes and well logs and

dating is provided by a bio-stratigraphic study of the 30/13-2 Josephine well.

Results

A seismic event exhibiting the earliest iceberg ploughmarks in the area is identified at a depth

of approximately 910m MSL and has been dated to approximately 1.9my at the UKCS 30/13-2

Josephine well. A featureless clay lithology recorded in well data extends upwards to a depth

of approximately 590m MSL and is followed by a sequence of interbedded sands and clays,

with occasional thin coals, lying beneath an erosion surface. Several ploughmarked intervals

are revealed by 3D timeslices within this sequence. An erosion surface characterised by deep

tunnel valleys at approximately 250m – 340m MSL is thought to be Elsterian in age by

reference to the position of the Bruhnes Matuyama event which is estimated from the

Josephine well dating study. The sequence between the ploughmarked near-base Pleistocene

event and the Elsterian erosion surface straddles the Early-Middle Pleistocene boundary and

comprises the Aberdeen Ground Fm.

Figure 1 Section illustrating seismic response, lithology and dating of the Aberdeen Ground Fm.

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The Middle to Late Pleistocene sequence overlying the Aberdeen Ground Fm. comprises

several seismo-stratigraphic units, including three generations of tunnel valley development

and a range of glaciogenic deformation fabrics, recording at least four separate glaciations.

Imbricated thrust sheet sets are closely associated with Elsterian tunnel valleys, a later

glaciation resulted in a second tunnel valley generation and some poorly defined fold structures

with occasional intervening thrust faults, while a third glaciation resulted in a mega-scale glacial

lineation and shallow deformation structures. Ice-loading of the seabed, presumably in the

Weichselian, has resulted in an opaque, chaotic texture extending a few tens of metres below

seabed in parts of the study area, grading into a highly disordered, faulted and folded texture

affecting the complete sequence elsewhere and extending more than 100m below seabed.

Shallow geology in this part of the CNS is a product of glacial deposition and subsequent

deformation and may vary considerably over short distances. Accurate characterisation of

shallow units is essential for rig installation and top-hole drilling strategies.

Figure 2 Sketch geological cross-section of Middle-Late Pleistocene seismo-stratigraphic units References Buckley F.A. 2012. An ice-moulded surface from the middle Pleistocene of the Central North Sea. Near Surface Geophysics, 2012 10, 333-346. Buckley, F.A. 2012. An early Pleistocene grounded ice sheet in the central North Sea. In: Glaciogenic Reservoirs and Hydrocarbon Systems. Special Publications, Vol 277. (Ed. M. Huuse, J. Redfern, D.P. Le Heron, R.J. Dixon, A. Moscariello and J. Craig) doi:10.1144/SP368.8. Geological Society, London. Gatliff, R.W., Richards, P.C., Smith, K., Graham, C.C., McCormac M., Smith, N.J.P., Long, D., Cameron, T.D.J., Evans, D., Stevenson, A.G., Bulat, J. & Richie, J.D. 1994. United Kingdom Offshore Regional Report, The Geology of the Central North Sea. British Geological Survey. HMSO, London. Knudsen, K.L. & Asbjörnsdóttir, L. 1991. Plio-Pleistocene foraminiferal stratigraphy and correlation in the central North Sea. Marine Geology, Vol 101, 113-124.

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Rigsite Geochemical Analysis of Cuttings Enables Optimisation Throughout the Life Cycle of the Well. Neil Cardy, Baker Hughes

Typically, drilled cuttings are analysed at the rigsite by the mud logger and/or wellsite geologist

using simple equipment. While useful and valuable, a simple description based on visual

inspection cannot give all the potential information contained within the cuttings. This lack of

information leads to the problems seen in US unconventional wells where a lack of knowledge

about the subsurface geology results in ineffective fracture stages and failure to reach

production targets.

Recent developments in technology make it feasible to use industry standard laboratory

techniques such as X-ray Fluorescence (XRF), X-ray Diffraction (XRD), pyrolysis and Scanning

Electron Microscope (SEM) analysis at the rigsite to analyse drilled cuttings in near real-time

while drilling.

Subsurface knowledge is critical to ensuring effectiveness and efficiency throughout the life

cycle of a well. Detailed geological information is needed to make operational decisions that

impact the production effectiveness of a well and drive down the costs.

XRF based elemental chemostratigraphic analysis along with SEM and pyrolytic analyses of

cuttings enable the use of proactive geosteering in massive shale formations. This results in

the lateral being landed accurately in the formation and also identifies potential “sweet spots”

by better understanding the depositional environment.

Geochemical analysis of the cuttings enables the reservoir to be characterised while drilling the

section and to also verify and calibrate both wireline and LWD logging responses, ensuring

accurate reserves estimates.

SEM and X-ray Diffraction mineralogical analysis along with the TOC content can identify the

optimal zones to hydraulically fracture to ensure the most efficient use of resources and obtain

maximum production. Additionally, identifying minor mineral components enable expensive

mistakes to be avoided when selecting completion techniques and fluids.

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Seismic Pore Pressure Prediction in the Norwegian Sea, Halten Terrace

Eyvind Aker, Ole Gunnar Tveiten, Phil Bailey, AGR, Karenslyst Allé 4, P.O.Box 444 Skøyen,

NO-0213 Oslo, Norway

Pre-drill pore pressure prediction is essential for safe and efficient drilling and is a key element

in the risk reducing toolbox when designing a well. Commonly, pore pressure prediction relies

on traditional 1D offset analysis. On the Norwegian Continental Shelf velocity data from seismic

surveys are often not considered. Our work with seismic interval velocities shows that the

velocity field can provide an important basis for pressure prediction and enable construction of

regional 3D pressure cubes. This increases the confidence in the pore pressure models and

aids the pre-drill geo-hazard screening process.

We demonstrate how a 3D velocity field can be converted to a 3D pore pressure cube using

reported pressure in offset wells as calibration points. The method is applied to a regional

dataset at the Halten Terrace in the Norwegian Sea; an area with a complex pattern of pore

pressure anomalies which traditionally has been difficult to map. The algorithm is searching for

a velocity to pore pressure transform that best matches the reported pressures. The 3D

velocity field is a proxy of rock velocity and is derived from seismic surveys and verified to

check shot velocities and sonic data in the offset wells.

We find that the modelled pore pressure fits well with reported maximum pore pressure in

Tertiary and Cretaceous. However, reported pore pressure is usually correct only at depths

where a reaction from borehole is registered (kick, connection gas or RFT pressure point). The

misfit, and thereby the uncertainty in the prediction, is quantified by the root mean square

(RMS) of the difference between modelled and reported pressures. Further lithologic

characterization, especially in Jurassic, is necessary to enhance the accuracy of the method.

Admittedly, geologic history and subtle lithological variations in limestone content will also

influence the velocity field.

Left: 3D velocity field based on interval velocities from seismic surveys and verified against check shot and sonic data. Right: A 2D map of the velocity field and the location of offset wells that were used for calibrating the pressure in the velocity to pore pressure transformation.

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0

0A 2D map of the modelled pore pressure using the best matching velocity to pore pressure transform. A complex pattern of pore pressure is demonstrated.

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Kvitebjørn Overburden Study

John David Jackson, Statoil

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Combined Service for PPFG Prediction and Drilling Performance Support

Nader Fardin, LR Senergy

Drilling performance and geomechanics can be treated in isolation by traditional well planning

practices to the detriment of overall drilling efficiency and risk reduction.

This poster highlights the value of an integrated pore pressure prediction and performance

drilling service for three wild cat wells drilled in deep water West Africa. The combined service

was planned to reduce pore pressure uncertainty, deliver significantly improved drilling

efficiency, mitigate risk and reduce NPT.

A full geomechanical model was produced from 3D seismic and far offset data. Uncertainties

remained meaning that while-drilling support allowed timely decisions to be implemented. The

far offset data was also analysed to optimise bit selection, hydraulics and BHA design in a

geologically challenging environment. The uncertainties initially led to ROP limitations that were

relaxed as pre-drill models were better defined and calibrated with the use of real time LWD

data.

Performance benchmarks and KPI’s for tripping speeds, casing running speeds and connection

procedures were established initially and allowed for targeted coaching and mentoring to be

implemented where requirement was identified.

The poster will show that the support made a significant contribution to the safe drilling of the

three wells and that significant performance improvements were made over the campaign.

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Definition of an Operations Geologist: The Art of Engaging People and

Possibilities.

Hozefa Godhrawala, Centrica Energy

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Advanced Surface Logging in the Life-Cycle of a Well

Gionata Ferroni, Geolog International

A key ingredient of success in well operations is the ability to react to change while drilling.

Identifying geological and drilling-related contingencies and managing operational change will

benefit from the use of advanced surface logging solutions. An essential requirement is

integration of data generated by such solutions in Real-Time decision-making processes.

Case studies are presented describing well operations that used unique or previously

disregarded data provided by advanced surface logging systems to optimise drilling and

improve real-time knowledge of reservoir, source rock and nature of formation fluids.

Case studies are based on direct physical measurements carried out on formation gases and

on rock cuttings as they are circulated out of the well while drilling.

Extending the identified hydrocarbon spectrum has been developed in parallel with isotopic

characterisation of carbon. Rock analysers that measure chemical, mineralogical and organic

carbon properties on site while matching necessary ruggedness with accuracy are available

and used in many well operations. Intelligent data analysis increases operational efficiency and

optimisation of drilling processes.

Progressive development of surface logging technology is transforming mud gas

measurements into a level of reliability sufficient to consider surface gas compositions as a

reliable picture of hydrocarbon fluid content in the mud.

Advanced surface logging is moving towards continuous, real time determination of reservoir

rock and fluid parameters.

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Operations Geologist Activities Review Under the LEAN Methodology

D. Garcia Cristobal1, J.W. Lall

1, D. Valhondo Solano

2, T. Polo Naranjo

1, K.E. Perez Huaynalaya

1, E.

Altamirano Oporto1, V. Rojas Pumacayo

1

1Geological Operations Latin America Region (Repsol)

2Innovation and Improvement Direction (Repsol)

The application of a manufacturing methodology developed to reduce the “Lead Time” in a

production chain to an Operations Geologist’s activities has no apparent sense; however, after

reviewing definitions and adapting some concepts, “Lean Thinking” becomes fully applicable.

The methodology involves the elimination of all non-essential activities to accomplish the

project targets, and redesign of improvable ones. The seven sources of waste (or “muda”)

identified by Lean are:

1. Overproduction, delivering products that are not demanded, or are produced too early,

such as superfluous reporting, nonessential meetings, extra preparation or excessive

tool runs;

2. Waiting, idle time where too many people are assigned to a project, people are

assigned too early; or waiting on decisions because too few people are assigned to a

task;

3. Transport, physical transportation of people or goods. It consumes time and does not

add any value;

4. Overprocessing, repetition of the same activities by several people or doing overly

complex products like too detailed final reports;

5. Inventory, overstock of tools in place, or keeping partial copies or reports that are

checked time after time to be sure if they are correct or not;

6. Reworking, re-doing an analysis, a report or a document several times due to

mistakes, or making additional logging runs due to failures in the tool or data

acquisition;

7. Motion, initially considered as physical movement, it is also the way we share

information or the efficiency with which a particular task is performed.

The analysis focuses on the typical places where waste is found: Strategy, and its wrong

aspects; People, with revision of their skills and organizational charts; the Process in place

with extra loops or products that are not required; and use of inefficient Technologies.

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Automation in Operations Geology – Opportunity or Anathema?

Samit Sengupta and Colin Maxwell, Geologix Limited

Automation in operations geology is at a very nascent stage today as our industry grapples

with easy wins in analytics and reporting. But there are areas that can be automated further.

The operations geologist plays a key role in this process and judicious use of accurate,

calibrated information will help the operations geologist to make better and faster decisions.

On the surface this would appear to be a great opportunity for the industry. Balancing drilling

efficiency with gaining sub-surface intelligence, however, is a tight-rope walk that the

operations geologist has had to tread carefully. A key factor in judgment calls are industry and

localized benchmarks that require statistics and KPIs to come into play. For example, “how the

average ROP achieved through a particular formation compares with an adjacent well drilled by

another operator considering that a higher ECD had to be maintained for a localized over-

pressure zone” is not just a matter of curiosity but an essential ingredient for performance

management.

The answers to these questions are not straightforward. They require the identification of

specific zones of interest before applying statistical analyses to gain the requisite insight. On a

daily basis, in spite of Excel replacing a calculator, the process essentially remains similar–

eyeball the log, pick out the zone of interest, import the data into a spreadsheet to perform the

calculations and share the results by producing a report. Isn’t this automation enough? The

answer is a resounding ‘NO’!

The challenge to the industry should remain a decision on what can be automated effectively

without impeding the easy interpretation of data for human decision making. This paper

explores how we can work towards systems that can automate the entire drilling process so

that human intervention will only be required in exceptional circumstances.

Automated creation of Microsoft Word from a composite log document for draft End of Well Report

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Surface Formation Evaluation: A New Approach to Improve, Complement and De-Risk Traditional Formation Evaluation and Characterization Methods. Ilaria De Santo

1 and Femi Tanimola

2

1Business Development Manager, Formation Evaluation, Geoservices, Paris

2Global Account Manager, Geoservices Schlumberger, London

Formation evaluation is still a risky and expensive exercise today, due to the increasingly

challenging environmental conditions (HTHP, highly deviated or horizontal wells) and the

complexity of the reservoirs being drilled (complex lithology, heavy oils, unconsolidated, tight or

fractured formations, etc.)

Today, we carry out Advanced Formation Evaluation at the well site, based on surface

measurements made on cuttings or hydrocarbon dissolved into the mud, which are carried to

surface during drilling. The objective of such new stream of technologies is to complement and

improve traditional Formation Evaluation done on wireline or the drill string. This ensures that

at least a minimum amount of data is provided when none of the traditional methods are

possible or practical. As cuttings and hydrocarbons in mud are present at surface every time a

well is drilled, independently from environmental conditions or wellbore geometries, taking

advantages of such technologies is the way forward.

The FlairTM technology allows extraction of hydrocarbon components from the mud under

controlled and repeatable thermodynamic conditions. The composition of the hydrocarbon

bearing fluid can in this way be accurately measured, into the C1-C5 range, while qualitative

composition analysis is done on the C6-8 range.

The combination of Flair and Isotope analysis at the well site allows us to assess the maturity

of the hydrocarbon encountered at the various depths, and this information can be used by the

Exploration Geologists to constrain existing petroleum system models and hence to plan the

location of the next well to be drilled.

The Lithology+ service offered by Schlumberger allows a very accurate and operator-

independent cutting description and characterization. High resolution images obtained with an

electronic microscope are taken, stored and can be displayed together with mineralogy and

elemental composition of the cuttings, to complete their lithofacies characterization. Synthetic

or measured Gamma Ray obtained from cuttings eliminates the uncertainty that has been

traditionally associated to this kind of measurements.

In addition, a fast TOC analysis can be done at the well-site, providing crucial information on

the evaluation of Unconventional reservoirs.

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Time Dependent Bore Hole Stability: New Technology to Address an Age Old Problem

Pat Spicer, Consultant to Dana Petroelum

How many times do we appear to have reached TD successfully, only to find that the hole is

decaying as we trip the BHA back to surface or worse still with casing or completion part way to

setting depth? It is common-place to attribute such problems to “Time-Dependent” borehole

instability. Gaining a better understanding of which formations are problematic and by

understanding, mitigating or at least better managing the issue, could pay substantial

dividends. However, we do not routinely log our holes in a manner that can help address this

issue. Routine collection of time lapse data, perhaps as simple a thing as caliper data could

help enormously. This poster presents a recent case history of collecting such data and poses

a challenge – can the Operations Geology community sell the value to the LWD providers to

give us the tools we need ?

On a recent horizontal production well we had reached TD. There were concerns about

stability at both toe and heel. A wiper trip was planned before POOH. It was suggested that

the hole condition for running the completion and placing swell packers be assessed by caliper

logging on the trip out. The hole looked good on the “as drilled” caliper. Had there been any

subsequent decay? It was concluded that the desire not to rotate on the trip out, unless

unavoidable, precluded this. The trip was slick and no problems were anticipated in running

the lower completion. The screens got 17 feet outside the shoe and stopped.

They were pulled to surface and a wiper trip planned. This time we logged caliper. A slow

pass because of caliper design. Time dependent decay was demonstrated and presumably

cleaned as on the 2nd attempt, the screens ran to plan.

There is no guarantee that if we had been able to log the caliper on the original trip out of the

hole, we would have avoided the failed completion run, but the cost of the failed run would

surely have justified trying, if we had had the tools available to us.

Modern LWD technology can deliver an extraordinary range of data types and the technologies

to deliver them have been developed because the demand for formation evaluation has made

this commercially attractive. Less attention has been given to tools to help us construct wells

more efficiently, but the commercial drivers are there. We just need to make the value clear to

the service providers and no doubt the technology will be developed.

The vision: a caliper tool that can collect data, while tripping, with pumps on or off, and even

without rotation.

Many providers build into their basic LWD tool capabilities beyond that which is always

required, so that as situations demand it, the extra capability can just be turned on. For

example, azimuthal GR. A further adaptation of the technology for oriented data collection

could provide oriented caliper data. Battery driven caliper data collection has already been

developed for situations where there is no flow to drive a turbine. So some of the elements

required already exist.

If the well construction community can articulate the value to the providers, surely this tool

could soon be with us.

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7100

7110

7120

7130

7140

7150

7160

7170

6 7 8 9 10 11

Fee

t M

D B

RT

Original Drilling Caliper Main Wiper Trip Caliper

Initial Wipe Caliper GR

Casing Shoe - Log Depth Hole Size

GR

0 120

Inches

Poor data due to

tool capabilities

Possible source of HUD

Clear, time

lapse hole size

increase

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Operations Geology Conference

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