example of field development ppt
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Example of Field Development PptTRANSCRIPT
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Shell U.K. Limited
Presenter: David Jones Fram Subsurface Team Lead, Shell U.K. Limited
Contributors Shell U.K. Limited: Samantha Large, Ahmed Helmi, Alan McQueen, Mensur Hodzic, Robert Cullen, Fola Sanwoolu, David Clutterbuck, Barry Meldrum, Bill Gray, Mark Robinson, Rob Jansen
DEVEX 2012
Fram Field Development Plan UK Central North Sea
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Definitions and Cautionary Note Reserves: Our use of the term “reserves” in this presentation means SEC proved oil and gas reserves and SEC proven mining reserves.
Resources: Our use of the term “resources” in this presentation includes quantities of oil and gas not yet classified as SEC proved oil and gas reserves or SEC proven mining reserves. Resources are consistent with the Society of Petroleum Engineers 2P and 2C definitions and includes Oil Sands.
Organic: Our use of the term Organic includes SEC proved oil and gas reserves and SEC proven mining reserves excluding changes resulting from acquisitions, divestments and year-end pricing impact.
Identified Items: This presentation refers to Identified Items which have been excluded from CCS earnings and EPS calculations. Please see page 4 of the Quarterly Results Announcement for a listing of those items.
To facilitate a better understanding of underlying business performance, the financial results are also presented on an estimated current cost of supplies (CCS) basis as applied for the Oil Products and Chemicals segment earnings. Earnings on an estimated current cost of supplies basis provides useful information concerning the effect of changes in the cost of supplies on Royal Dutch Shell’s results of operations and is a measure to manage the performance of the Oil Products and Chemicals segments but is not a measure of financial performance under IFRS.
This presentation contains forward-looking statements concerning the financial condition, results of operations and businesses of Royal Dutch Shell plc. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements are statements of future expectations that are based on management’s current expectations and assumptions and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements. Forward-looking statements include, among other things, statements concerning the potential exposure of Royal Dutch Shell plc to market risks and statements expressing management’s expectations, beliefs, estimates, forecasts, projections and assumptions. These forward-looking statements are identified by their use of terms and phrases such as ‘‘anticipate’’, ‘‘believe’’, ‘‘could’’, ‘‘estimate’’, ‘‘expect’’, ‘‘intend’’, ‘‘may’’, ‘‘plan’’, ‘‘objectives’’, ‘‘outlook’’, ‘‘probably’’, ‘‘project’’, ‘‘will’’, ‘‘seek’’, ‘‘target’’, ‘‘risks’’, ‘‘goals’’, ‘‘should’’ and similar terms and phrases. Also included as forward-looking statements in this presentation is our disclosure of reserves, proved oil and gas reserves, proven mining reserves, resources, and all future estimates of refining capacity, oil and gas production, capital investment and expenditure, cash from operations, dividends, share buybacks and investments. There are a number of factors that could affect the future operations of Royal Dutch Shell and could cause those results to differ materially from those expressed in the forward-looking statements included in this presentation, including (without limitation): (a) price fluctuations in crude oil and natural gas; (b) changes in demand for the Group’s products; (c) currency fluctuations; (d) drilling and production results; (e) reserve estimates; (f) loss of market share and industry competition; (g) environmental and physical risks; (h) risks associated with the identification of suitable potential acquisition properties and targets, and successful negotiation and completion of such transactions; (i) the risk of doing business in developing countries and countries subject to international sanctions; (j) legislative, fiscal and regulatory developments including potential litigation and regulatory effects arising from re-categorisation of reserves; (k) economic and financial market conditions in various countries and regions; (l) political risks, including the risks of expropriation and renegotiation of the terms of contracts with governmental entities, delays or advancements in the approval of projects and delays in the reimbursement for shared costs; and (m) changes in trading conditions. All forward-looking statements contained in this presentation are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. Readers should not place undue reliance on forward-looking statements. Additional factors that may affect future results are contained in Royal Dutch Shell’s 20-F for the year ended December 31, 2008 (available at www.shell.com/investor and www.sec.gov). These factors also should be considered by the reader. Each forward-looking statement speaks only as of the date of this presentation. Neither Royal Dutch Shell nor any of its subsidiaries undertake any obligation to publicly update or revise any forward-looking statement as a result of new information, future events or other information. In light of these risks, results could differ materially from those stated, implied or inferred from the forward-looking statements contained in this presentation. There can be no assurance that dividend payments will match or exceed those set out in this presentation in the future, or that they will be made at all.
The term “Shell interest”is used for convenience to indicate the direct and/or indirect (for example, through our 34% shareholding in Woodside Petroleum Ltd.) ownership interest held by Shell in a venture, partnership or company, after exclusion of all third-party interest.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this presentation that SEC's guidelines strictly prohibit us from including in filings with the SEC. U.S. Investors are urged to consider closely the disclosure in our Form 20-F, File No 1-32575, available on the SEC website www.sec.gov. You can also obtain these forms from the SEC by calling 1-800-SEC-0330.
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Overview
Fram location and overview
Exploration and appraisal history
Key subsurface uncertainties
Subsurface development concept
Well and completion design
Surface development concept
Project schedule
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Fram Field Location - UK Central North Sea
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Regional Geology - Structural and Depositional Setting
UK Central North Sea - Quad 29 Southwest part of Central Graben Northeast of Curlew Horst and west of Puffin Horst Penetrative salt diapir structure (Zechstein salt) Salt diapir above Late Jurassic footwall high Deep structure controlled by Mesozoic rifting
Palaeocene Forties Sandstone Member Basin-floor distal turbidite deposits ‘Sheet-like’ sands deposited in lobe sequences SW margin of main NW-SE Forties fan Distal and marginal location Further down depositional dip than analogues
Palaeocene isochron thickness map (Top Sele – Top Chalk)
Base Cretaceous unconformity surface from 3D seismic data
Fram
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Regional Geology - Stratigraphic Summary
Fram
Fram Discovery Overview
Field Summary
UK Central North Sea
Oil rim with primary gas cap
HCIIP 390 MMboe (approx.)
P.012 Licence (Shell 28% Esso 72%)
P.1664 Licence (Shell 50% Esso 50%)
Palaeocene Forties Sandstone reservoir
Porosity 18-28%, Perm 0.1-100mD
Discovered in 1969 by 29/3-1 well
Appraised in 1999 with 29/3a-6 well
Appraised in 2009 with 29/3c-8, 8z wells
300 ft TVD thick oil rim (approx.)
>1500 ft TVD gas column (approx.)
Top Forties depth map 2010 (PSDMcorr)
29/3c
29/8a
29/4c
29/9c
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Fram Salt Diapir - 2007 PSDM Near-Stack Reflectivity Data TW
T (m
s)
West East
1700
2664
29/8a-4 29/3-1 29/9c-7
Top Forties time horizon
Salt diapir
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Forties Reservoir Geology - Facies Scheme Summary
~
1
m Thin Bedded sheet sands and siltstones (heterolithics) (HM)
<1ft thick sands interbedded with shales
Thick amalgamated sands 3 – 15 ft thick Well 29/3c-8
Top Forties
T75MFS
T70MFS
Ross Formation, County Clare, Ireland
Fan 3, Karoo, South Africa
Fan A Grootkloof, Karoo, South Africa
Amalgamated Sands (A)
Heterolithic Medium (HM)
Heterolithic Thin (HT)
Gra
in s
ize,
sor
ting
Perm
eabi
lity
Kv /
Kh
Satu
ratio
ns
Facies Facies A
Facies HM
Facies HT
Forties Reservoir Thinning - Forties Isochore Thickness Map
29/3c
29/8a
29/3b
29/4c
29/9c
Salt
Forties fan margin
Thick and high N/G Forties to NW
Thinning of Forties and N/G reduction
to SE
29/8a-4 side lobe
Thin and low N/G Forties to SW of salt
diapir
Lista high
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Oil Rim Characterisation - 29/3c-8,8z Appraisal Wells 2009
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Key Subsurface Field Development Uncertainties
Reservoir properties
Thickness of T75 reservoir zone relative to fluid contacts.
N/G variation and rate of reduction towards Forties pinch-out.
Facies distribution and proportions in southern area of field.
Permeability of reservoir sands (for well kh/PI).
Reservoir architecture
Stratigraphic connectivity (lateral extent of sands and shales).
Structural connectivity (influence of faults on fluid flow/pressure depletion).
Fram Proposed Development Well Locations
Block 29/3c
Block 29/8a
Block 29/9c
Block 29/4c
P3
P1
P1z P2z
P2 P4
G2
G4
PWRI
G3
P5
FWL
GOC
DCE
DCW
DCW
DCE
G2
P5
P3
P1z
P2z
P4
P1 pilot
P2 pilot PWRI
G3
G4
Fram Proposed Development Well Locations (3D view)
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Development Well Planning/Placement - Horizontal Wells
Horizontal oil and gas producers - well design considerations and objectives
Pilot holes to constrain depth uncertainty and determine depth of OWC for horizontal well placement.
Cross-cut reservoir layers in T75 reservoir zone to maximise stratigraphic connectivity.
Wells to target upper and lower Amalgamated Sand (A) packages based on Vsh seismic inversion volumes.
4000ft AH well lengths to optimise well spacing/drainage and kh (due to layered reservoir and low perm).
Optimise stand-off from GOC and OWC to mitigate early gas and/or water breakthrough to wells.
P1_hor_oil_producer
29/3c-8z
29/3c-8
GOC
Top Forties Top Sele
Top Lista Well designed to cross cut stratigraphy from Top Forties to T75MFS
GOC
29/3c-8z
29/3c-8
Top Forties
Top Sele
T75MFS Top Lista
‘PROMISE’ seismic inversion P50 Vsh volume in Petrel Facies model in Petrel (base case)
P1_hor_oil_producer
T75MFS
Well targeting both lower and upper amalgamated sands
Fram Well Concept Design - 4000 ft AH Horizontal Wells
Ocean Guardian drilling rig
Well Concept Design Summary
Conventional CNS ‘5 string’ casing design 13 5/8” intermediate casing shoe at 7000ft MD Batch drilling of top hole and intermediate sections Water based mud system to be used in 17 ½” hole 9 5/8” production casing set in Forties reservoir 4,000 ft AH Forties reservoir sections in 8 ½” hole Ocean Guardian semi-sub drilling rig Expected drilling start date July 2012 Wells to be cleaned-up to rig prior to suspension
Fram Well Completion Design
Well Completion Concept
Wire wrapped screens with swellable packers.
5 ½” 13Cr sand screens with 316L wrap material and 200 micron slot size.
Swellable packers for water/gas shut-off capability.
Resman chemical tracers (oil and water sensitive).
Dual Permanent downhole pressure gauges (PDHG).
Gas lift completion for oil wells.
Through tubing access to reservoir for interventions (e.g PLTs).
Gas well completion as per oil well completion (without gas lift or chemical tracers and single PDHG).
Wire wrapped sand screens ‘Resman’ chemical tracers
Field: FRAM Well Type: Oil Producer Rig: Ocean Guardian
Block: First Completed: New Drill DFE: 85
Well No.: P1 z Workover Date: Water Depth: 321
Platform: N/A Annulus Fluid: Max dev: 90 ft ahbdf
Fluid Weight, pptf: Max dogleg: ft ahbdf
MD, ft TVD, ft Dev, o min ID" max OD" Drift" Length
406 406 0.0 4.75/1.875 18.600 18 3/4 Wellhead Housing
Vetco 5" x 2" Dual Tubing Hanger ( w ell head datum)
Top 35" Conductor Housing Seabed
1.640 2.726 1.781" RN Nipple Profile
1.700 2.628 Halliburton 2 3/8" WEG ( restricted ID) 13CR
4.892 6.033 4.767 5 1/2" 17# Vam Top HT 13CR L80 Tubing
2000 2000 0.0 4.625 8.220 SCSSV
2050 2050 0.0 10 3/4" x 9 5/8" Casing Crossover
TBA #VALUE! #N/A 4.597 7.069 SPM
3000 3000 0.0 20" Casing shoe
TBA #VALUE! #N/A 4.597 7.069 SPM
TBA #VALUE! #N/A 4.597 7.069 SPM
7350 6790 30.4 13 5/8" Casing Shoe
9380 8426 48.7 4.597 7.069 Dow nhole Dual Gauge Mandrel. Tubing & Annulus
Min distance betw een gauges is 300ft TVD
9880 8726 57.7 4.597 7.069 Dow nhole Pressure and Temperature Gauge
9940 8757 58.8 4.562 6.860 4.767 SSD
10000 8788 60.0 4.875 8.310 4.767 Hydrostatic Packer
10100 8837 61.9 4.892 6.000 4.767 Liner Hanger Packer (ZXP/Quantum/SC2R)
10102 8838 61.9 6.000 7.699 6.000 7", 32#, 13CR, Vam Top HT, ALT. 6" Drift
10242 8900 64.6 4.780 5.940 4.653 Mule shoe
10262 8909 65.0 7" x 5.5" X Over
5 1/2" 17# Vam Top HT 13CR L80 Tubing 1 joint
10312 8930 65.9
4.562 8.015 4.562 Fluid Loss Device (FIV/FS2)
10928 9120 78.8 9 5/8" Casing Shoe
4.892 8.100 4.767 Sw ellable Packers
4.892 6.190 4.767 5 1/2" 17lbs 13Cr L80 Wire Wrap Screens 200 Microns
15408 9150 90.0 Bull Nose Float Shoe
Prepared by: Checked by: Rev No.: 2 Date: 02-May-2012
Other InformationDescriptionSchematic
Barry Meldrum
Proposed Completion
Fram Field Development Plan - Subsea layout
Subsea Design Summary 8 x subsea production trees – 5 oil and 3 gas. 4.4 km integrated flowline bundle. 2 x towhead production manifolds. Flexible risers from bundle midline structures to FPSO. 1 x subsea produced water re-injection (PWRI) tree. 2 km umbilical from PWRI tree to DCE towhead manifold. 3 km flexible flowline connecting the PWRI tree to the FPSO 18 km14” carbon steel gas export pipeline. Tie-in point to 20” export line at Curlew Deep Gas Diverter. Pipeline end manifold (PLEM) at the Deep Gas Diverter.
Schematic of a towhead production manifold Subsea tree ‘coccoon’ structure
Proposed subsea layout and pipeline routes
Subsea tree spacing around towhead manifold
Fram Field Development Plan - FPSO and Subsea Facilities
Fram Field Production Forecasts (base case)
0
2000
4000
6000
8000
10000
12000
14000
Oil
bo
pd
Year
Oil rate bopd
0
20
40
60
80
100
120
140
Gas
MM
scf/
d
Year
Gas rate MMscf/d
Gas production profile —5 oil production wells + 3 gas wells —Gas rate includes free + solution gas —Peak gas rates approx. 183
MMscf/d (monthly average)
Oil production profile —5 oil production wells + 3 gas wells —Oil rate includes crude + condensate —Peak oil rates approx. 18 kbopd
(monthly average) —Oil rate decline driven by GOR
development and water cut (gas cap expansion drive)
Fram FPSO Development Project Schedule (Level 0)
FEED
FEED
DESIGN
PROCUREMENT
HULL
TOPSIDES
INTEGRATION & COMM.
BUNDLE - DESIGN, PROCURE & FABRICATE
2012 2013 2014
DE
CC
F
PS
O
SU
BS
EA
DCE P1664 DCW
SELECT
FEED
P1664 Commitment – 12/02/13 P.012 License Expiry – 17/12/14
First Oil
PIPELINE - DESIGN, PROCURE & FABRICATE
PIPELINE INSTALL
BUNDLE INSTALL
INTEGRATION & COMM.
SAIL
HU & C
RISER INSTALLATION
2011
WE
LL
S
Development
drilling start
Onstream
FPSO hook-up
FID
Subsea
installation