Offshore field experience with BrightWater

Transcription

1 Offshore field experience with BrightWater Presenter: Nancy Lugo Chevron Upstream Europe Stavanger 20/01/2010 Team Members: Nancy Lugo, David May, Elaine Campbell Chevron Upstream Europe, Aberdeen Rick Ng, Steve Cheung Energy Technology Company, Houston, Texas Chevron 2005 DOC ID

2 Agenda What is BrightWater Applications in the world BrightWater in Strathspey Strathspey field and geology BrightWater treatment in Strathspey Modeling process Treatment execution Results Lessons Learned Conclusions 2

3 What is BrightWater Novel particulate system for in depth waterflood conformance control Co-developed between Chevron, BP and Nalco Small cross-linked polymer particles bullheaded into injection well Propagate deep into the reservoir Once heated polymer expands to block pore throats and prevent further fluid flow through rock Injected water diverts into less swept zones 3

4 STC BrightWater applications Milne Pt 2004 Prudhoe 2004/05 (3) NWFB 2005 (2) Arbroath 2002 Strathspey 2006 Tangri 2006 Horn Mt 2006 BW for carbonates Minas 2001 Kotabatak 2006/07 PanAm 2006 Barrow Island Completed Planned Development 2001 Minas Field Indonesia (Chevron operated) Extra oil observed (SPE 84897) 2002/03 Arbroath, North Sea (BP) No extra oil. Ownership changes & production issues stopped assessment of field benefit. 2004/05 Alaska - Milne Point & Prudhoe Bay (BP) Over half a million extra barrels recovered from four trial wells. Treatment cost of just $ $3.80 per barrel Strathspey Over 130 mboe increase first 12 months. Treatment cost of $3.5 - $4 per boe. 4

5 Brightwater treatment in Strathspey Field Subsea development Consists of a tilted fault block (10 West) Two Reservoirs Brent Group (Black Oil) Banks Group, Statfjord Fm. (Gas Condensate) Production Mechanism Brent: water flooding, best candidate for BrightWater application Statfjord: depletion drive Brightwater deployed in Brent reservoir Upper Brent Reservoir Lower Statfjord Reservoir Brent W Dunlin Statfjord Triassic

6 Strathspey Brent Geology W Main Field Reservoir Units Dip 10 West Reworked Rotated Fault Blocks E M6 Injector M10 MS9 MS19 2d B C D GR F ER Original OWC -9380ft TVDSS Top B7 Top B6 Top B5 1km Top Brent Depth Structure 1000ft Top B4 Top B3 Brent Central MS9 MS19 Top B2 Top B1 M6 M10 Top Dunln Log Section Favorable mobility ratio has led to efficient sweep in general Main Field wells Geological heterogeneity and complex faulting in the slumped areas has led to localized early water breakthrough and poorer waterflood efficiencies. Brent South M5 M9 M11 M3 12 MS14 M15z M7 5 1km 6

7 Cumulative RBO Produced MS14 as candidate for BW treatment MS19 Cumulative Plot 2003 For Every 100 RBW Produced Top Brent Depth Structure MS14 to MS rbo 53rbo 18rbo Brent Central MS19 MS9 M10 M6 MS14 227rbo km M9 M15z Cumulative RBW Produced Fast watercurt development at MS19 after MS14 injection started Reservoir simulation indicated high oil saturation around MS19. Conventional water shut-off methods require well intervention Cost prohibitive in a subsea environment BrightWater treatment recommended for well MS14 Treatment deployed in September 2006

8 Cross Section (W-E) along MS19 well path Reworked fault blocks Faults act as baffles not sealing M6 injector give underlying support but not enough direct support within the fault compartments MS14 considered a good injector candidate as it could sweep north towards the faulted compartments Hard to get efficient sweep in this area Cross Section 1 - along MS19 Well Path Top Brent Depth Structure MS14 to MS19 Brent Central 1km M6 MS19 MS9 M10 M9 Cross Section 1 Cross Section 2 MS14 M15z MS19 Cross Section 2 Rework Fault -9380ft TVDSS OWC B5 B3 250m W Main Field Rework E

9 Cross Section MS14 to MS19 N to S fault structure indicates channeling was likely Top Brent Depth Structure MS14 to MS19 Perm differences between layers indicated thief zones were likely Possible improved vertical sweep efficiency was a target MS14 was proposed as target for BW Brent Central M6 MS19 MS9 M10 Cross Section 1 Cross Section 2 MS14 Cross Section 2 - MS14 to MS19 1km M9 M15z MS14 MS19 Rework Fault B5 High Perm Layer Rework Main Field S 250m -9380ft TVDSS OWC N

10 STC Modeling Process BrightWater Temperature regime around injector Extent of open perfs in MS19 Use tracer Determine well-well transit time and temp (help select best grade for the application) Look at where the bulk injected BW would go MS14 Temperature Profile MS19 intersecting MS14 Layer 7 Cooling around Tracer Concentration Layer 7 (part of B5): Black lines show position of sealing or part-sealing faults Bulk BW would go Thief layer Flank injector MS14 Layer 7: grid blocks in the main area are 125ftx125ft so 700ft is cooled towards MS19 Tracer in Layer 7 thief: 3 months after injection 10

11 STC Modeling Process BrightWater (cont ) Determine BrightWater Grade using Lab Tests Check activation times using bottle tests Inject selected BW grade into sand packs to check activation time/strength Calculate Resistance Factor Reservoir core test to select optimum formulation 11

12 STC Modeling Process BrightWater (cont ) Predict Incremental Oil Run full waterflood history match Reduce permeability in the model at the position reached by tracer after heating MS19 intersecting Layer 7 Rerun tracer (assess if water takes a different route) Flank injector Predict oil recovery with and without BW Predict incremental oil MS14 Calculate required treatment quantity Layer 7: grid blocks in the main area are 125ftx125ft so 700ft is cooled towards MS1 BW - Total Incremental: mboe 12

13 STC Treatment Execution STRATHSPEY SUBSEA LAYOUT BRENT IGLOO BRENT 'A' BRENT RECEIVER TEE STRUCTURE Satellite wells SATELLITE WELLS MS9(B) & MS14(B) Fore and aft cluster wells 16" WELGAS PIPELINE Gas to St Fergus via FLAGS system NINIAN CENTRAL 16" GAS EXPORT MS14 INJECTOR M6 (WI) M5 (WI) 'F' CLUSTER WELLS M1(S) M10(B) M2Z(S) M3(B) M4(S) Manifold 'A' CLUSTER WELLS M9(B) M7(B) M8(S) Liquids to Sullom Voe through Ninian pipeline SUDS GAS EXPORT SSIV/LAUNCHER SSIV UMB. E/H CONTROLS TEXACO SSIV PROTECTION STRUCTURE 2 Brent lines, 2 Statfjord lines, methanol and utilities lines 12" WATER INJECTION Water injection from Ninian South NINIAN SOUTHERN 13

14 Brightwater Treatment - Logistics Planned 140,000 litres Brightwater 70,000 litres BW Surfactant Spiked to 58,000 BBL Injection Water 1.5% Polymer Concentration Pump Time at 22,000 bpd (15bpm) Actual 2.7 DAYS Metering Error First Half Of Polymer Treatment At 1% Second Half At 1.5%

15 19/12/ /06/ /12/ /06/ /12/ /06/ /12/ /06/ /12/ /06/ /12/ /06/2007 BOEPD Oil Rate (bopd) Watercut Results 8,000 MS19 Pre and Post BW , , , , , , ,000 7,000 9,000 11,000 13,000 15,000 17,000 19,000 Total Fluid Rate (bpd) bopd 2003 bopd 2007 %wtcut 2003 %wtcut 2003 MS19 Production History In 2007 the watercut appeared to be more controlled. Under similar voidage replacement conditions water cut accelerated to 80% over a matter of nine months in 2003 BrightWater slowed down the passage of water considerably between injector and producer. Allows MS19 to flow naturally at higher fluid rates with lower water-cut Data indicated oil production rise of 575 boepd. Incremental of 130 MBOE first year Total incremental hydrocarbon estimated to rise to 317,300 boe Base BOE Inc BOE 15

16 Best Practices and Lessons Learned Best Practices. Committed cooperative efforts among operators, vendors and research insititutes can deliver innovative technologies for enhancing hydrocarbon recovery. Investigate all data available to determine transit time between injector and producer. Consider an interwell tracer test first if there is a chance of very rapid connection between wells Simple simulation studies add valuable insights to the design and provide useful estimation of incremental oil recovery. Lessons Learned. Long term operator commitment is needed assign resource, monitor results and document. Failure of of crucial subsea equipment can make monitoring of well performance very difficult for long periods until opportune availability of vessels is possible. More thorough yard trials for pumping Brightwater should be conducted with the vendor and operator personnel present. 16

17 Conclusions Brightwater was successfully deployed via a 10 mile subsea water injection line from the Ninian South Platform The treatment reduced the rate of water injection channeling between injector MS14 and producer MS19. The impact on MS19 is that the well can produce at a higher total fluid rate with a lower watercut leading to increased oil production. Incremental oil delivered in the first 12 months is 130,000 boe. 17

18 STC Any questions? 18