The 5 thru-tubing projects in the Lake Washington Area were mostly economically successful. Total costs were $855.1 million with 83.2% of the estimated costs. Cumulative oil production was 12,820 barrels with payout achieved in 34 days. Lessons learned included planning for weather delays when working in winter, that thru-tubing gravel packs can be effective sand control, and thru-tubing work can be done without coiled tubing to reduce costs.
Field Development Project : Gelama MerahHami Asma'i
A green field development project located in Sabah Basin comprises the whole upstream field development cycle from geology, reservoir studies to production facilities and economics. The objective is to come out with the best strategy to develop the field starting from our very own effort of reservoir characterization out of log and core data. Under supervision of lecturers, this project was completed as per scheduled.
Among new technical methodologies applied upon the completion this project:
1. Cubic Spline Interpolation Method in bulk volume calculation
2. Monte Carlo probabilistic method in reserve estimation
3. Reservoir Opportunity Index (ROI) method in well placement
Project was assessed by PETRONAS custodians.
Joel Hirschboeck, Kwik Trip, presented information on the Natural Gas Applications for Off-Road Vehicles for our Natural Gas for Transportation Roundtable in Mequon, WI.
OPERATING A COMPOST FACILITY
TO MAXIMIZE CARBON CREDITS
Jim Lapp
Supervisor Composting Operations
&
Allan Yee
Senior Engineer, Organics Processing
City of Edmonton
Field Development Project : Gelama MerahHami Asma'i
A green field development project located in Sabah Basin comprises the whole upstream field development cycle from geology, reservoir studies to production facilities and economics. The objective is to come out with the best strategy to develop the field starting from our very own effort of reservoir characterization out of log and core data. Under supervision of lecturers, this project was completed as per scheduled.
Among new technical methodologies applied upon the completion this project:
1. Cubic Spline Interpolation Method in bulk volume calculation
2. Monte Carlo probabilistic method in reserve estimation
3. Reservoir Opportunity Index (ROI) method in well placement
Project was assessed by PETRONAS custodians.
Joel Hirschboeck, Kwik Trip, presented information on the Natural Gas Applications for Off-Road Vehicles for our Natural Gas for Transportation Roundtable in Mequon, WI.
OPERATING A COMPOST FACILITY
TO MAXIMIZE CARBON CREDITS
Jim Lapp
Supervisor Composting Operations
&
Allan Yee
Senior Engineer, Organics Processing
City of Edmonton
Process Group has an established track record as a leading Global solutions provider for the Energy Industry. As well as designing and fabricating complete process trains, our expertise extends to installation, commissioning and servicing of your plant. For further details of how we can help you refer to www.processgroupintl.com.
ARB Midstream: Condensate from the Rockies Producing RegionAdam Bedard
Lease condensate production from the Rockies (Williston, PRB, DJ) projected to grow by 84,000 b/d, from 266,000 b/d to 350,000 b/d, over the next five years
95% of that growth is from the DJ Basin
Lease condensate production can be blended into the pipelines, but pipelines have specs that limit the % light ends
However, excess takeaway capacity and batching make hitting any sort of “blend wall” difficult
Possibly a problem only in the DJ, depending on how concentrated the barrels area
Rail can access the Canadian diluent market or Gulf Coast market (Splitters/Exports) and provide an uplift to distressed light barrels
However current pipeline capacity is causing previously distressed barrels to receive a higher price, closing the arb.
Rail provides Rockies’ producers with a coastal market, rather than only delivering a Cushing market
Producers can get Brent-based pricing
Premier Oil Investor Presentation 2017-FebruaryOILWIRE
Premier Oil Investor Presentation 2017-02-17, 2016 Highlights - High Operating Efficiency, Step Change in Production, Continued Portfolio Upgrading, Cost Reductions, Refinancing in Progress.
Moffett Base-Wide Groundwater Update, September 10, 2009Steve Williams
Former Moffett Federal Airfield Base-Wide Groundwater Program Update: Presentation to the Moffett Restoration Advisory Board Meeting September 10, 2009
ResAssure - The World’s Fastest Reservoir Simulator | A Revolution in Reserve...Stochastic Simulation
This Presentation Will:
1. Introduce a new way of evaluating reservoir uncertainty with RESASSURE
2. Illustrate the concepts used
3. Highlight the benefits achieved
4. Demonstrate the value of the results
Stochastic Simulation has unleashed the world’s fastest reservoir simulator, ResAssure, which is set to revolutionize production planning and reserves reporting in the Oil & Gas industry.
ResAssure easily computes > 1 Million realisations within a 24 hour period, a fraction of the time it currently takes with traditional methods and software packages. The release of ResAssure marks a significant milestone in the history of reservoir simulation – the first real industry technology advance in 30 years.
Dr Wadsley, Chief Technology Officer at Stochastic Simulation, commented “ResAssure is capable of quickly generating more accurate reserve estimates than is currently possible by any other software system. The approach taken generates a complete distribution of history matched models all of which are consistent with the geological model and observed production history. The time taken for this is orders of magnitude faster than current history matching methods.”
“Field development planning based on ResAssure’s distribution of models (rather than just upon a single history-matched model using conventional methodologies) will significantly reduce uncertainty and risk.” he added.
By enabling faster and more accurate analysis of dynamic subsurface geological data than has previously been possible, ResAssure markedly reduces the risk in the development of oil and gas fields by narrowing the range of uncertainty in reserves estimates: thereby supporting better production and financing decisions, with substantial increases in project ROI.
ResAssure’s innovation in reservoir simulation solves fully-implicit, dynamic three-phase fluid flow equations for every geological realisation. The speed breakthrough was achieved by a combination of proprietary algorithms, polygonal gridding and aggressive spatial coarsening and time stepping, based upon a conventional finite-difference discretization of the reservoir.
Key Insights Identified:
1. Consistency between volumetric, material balance and fractional flow places very strong constraints on feasible reservoir models.
2. The mathematics of reservoir simulation is NOT complex – it is the geology which is complex.
3. Reserves uncertainty is not quantified, but estimated from current ‘best’ estimate in an ad hoc unsystematic way.
4. What’s the point of preserving mass balance in the simulator when the hydrocarbons in the reservoir are imprecise and we don’t include all production data – mass balance should act to regularise our solution, not to define it.
5. The role of reservoir simulation is not to compute an exact solution of a poorly defined geological model – it is to define a range of feasible reservoir models and associated production forecasts.
Process Group has an established track record as a leading Global solutions provider for the Energy Industry. As well as designing and fabricating complete process trains, our expertise extends to installation, commissioning and servicing of your plant. For further details of how we can help you refer to www.processgroupintl.com.
ARB Midstream: Condensate from the Rockies Producing RegionAdam Bedard
Lease condensate production from the Rockies (Williston, PRB, DJ) projected to grow by 84,000 b/d, from 266,000 b/d to 350,000 b/d, over the next five years
95% of that growth is from the DJ Basin
Lease condensate production can be blended into the pipelines, but pipelines have specs that limit the % light ends
However, excess takeaway capacity and batching make hitting any sort of “blend wall” difficult
Possibly a problem only in the DJ, depending on how concentrated the barrels area
Rail can access the Canadian diluent market or Gulf Coast market (Splitters/Exports) and provide an uplift to distressed light barrels
However current pipeline capacity is causing previously distressed barrels to receive a higher price, closing the arb.
Rail provides Rockies’ producers with a coastal market, rather than only delivering a Cushing market
Producers can get Brent-based pricing
Premier Oil Investor Presentation 2017-FebruaryOILWIRE
Premier Oil Investor Presentation 2017-02-17, 2016 Highlights - High Operating Efficiency, Step Change in Production, Continued Portfolio Upgrading, Cost Reductions, Refinancing in Progress.
Moffett Base-Wide Groundwater Update, September 10, 2009Steve Williams
Former Moffett Federal Airfield Base-Wide Groundwater Program Update: Presentation to the Moffett Restoration Advisory Board Meeting September 10, 2009
ResAssure - The World’s Fastest Reservoir Simulator | A Revolution in Reserve...Stochastic Simulation
This Presentation Will:
1. Introduce a new way of evaluating reservoir uncertainty with RESASSURE
2. Illustrate the concepts used
3. Highlight the benefits achieved
4. Demonstrate the value of the results
Stochastic Simulation has unleashed the world’s fastest reservoir simulator, ResAssure, which is set to revolutionize production planning and reserves reporting in the Oil & Gas industry.
ResAssure easily computes > 1 Million realisations within a 24 hour period, a fraction of the time it currently takes with traditional methods and software packages. The release of ResAssure marks a significant milestone in the history of reservoir simulation – the first real industry technology advance in 30 years.
Dr Wadsley, Chief Technology Officer at Stochastic Simulation, commented “ResAssure is capable of quickly generating more accurate reserve estimates than is currently possible by any other software system. The approach taken generates a complete distribution of history matched models all of which are consistent with the geological model and observed production history. The time taken for this is orders of magnitude faster than current history matching methods.”
“Field development planning based on ResAssure’s distribution of models (rather than just upon a single history-matched model using conventional methodologies) will significantly reduce uncertainty and risk.” he added.
By enabling faster and more accurate analysis of dynamic subsurface geological data than has previously been possible, ResAssure markedly reduces the risk in the development of oil and gas fields by narrowing the range of uncertainty in reserves estimates: thereby supporting better production and financing decisions, with substantial increases in project ROI.
ResAssure’s innovation in reservoir simulation solves fully-implicit, dynamic three-phase fluid flow equations for every geological realisation. The speed breakthrough was achieved by a combination of proprietary algorithms, polygonal gridding and aggressive spatial coarsening and time stepping, based upon a conventional finite-difference discretization of the reservoir.
Key Insights Identified:
1. Consistency between volumetric, material balance and fractional flow places very strong constraints on feasible reservoir models.
2. The mathematics of reservoir simulation is NOT complex – it is the geology which is complex.
3. Reserves uncertainty is not quantified, but estimated from current ‘best’ estimate in an ad hoc unsystematic way.
4. What’s the point of preserving mass balance in the simulator when the hydrocarbons in the reservoir are imprecise and we don’t include all production data – mass balance should act to regularise our solution, not to define it.
5. The role of reservoir simulation is not to compute an exact solution of a poorly defined geological model – it is to define a range of feasible reservoir models and associated production forecasts.
Why 3D Laser Scanning Technology Lowers Brownfield Capital Construction CostsAVEVA Group plc
Day & Zimmermann provides laser scanning and 3D data capture technology solutions to create a digital facility integrated into the design phase of capital projects. This solution, using AVEVA technology, provides customers with a tremendous return on their investment, including cost and schedule savings, and the ability to reuse the data to establish work processes on future projects. Read this presentation to learn how 3D technology can help industrial plant owners manage their business, save money, reduce risk, and increase capacity and efficiency.
Discover how AVEVA can save you money and reduce risk!
www.aveva.com
Advisian Digital Enterprises hosted the COMIT community day at Brentford in March 2015 at WorelyParsons. These slides were presented during their showcase slot.
RV Thuwal - Refit project overview by Maritime Survey AustraliaMichaelUberti
KAUST engaged Maritime Survey Australia to act as a project manager to oversee a major refit of the vessel, RV Thuwal which involved wiring upgrades, installation of new navigational equipment, a new galley, a scientific survey room and a vessel upgrade of the hydraulics, heating, ventilation and cooling systems.
Descon Engineering, UAE recently completed ENOC Refinery Shutdown-2016 and this Case Study is being written to share the success story with industry professionals. The case study include the introduction, challenges we faced and solution for these challenges. The conclusion include the appreciation from ENOC for completing the project in time, and with highest standard of safety and quality.
SELA Region Q4-2013 Thru-tubing Recompletion and Thru-tubing Workover
1. SELA Region Q4-2013 Thru-tubing
Recompletion and Thru-tubing
Workover Program
Project Performance Report
2. Project Summary
• 5 TTRC & TTWO projects in Lake Washington Area
• 4/5 projects were economically successful
projects
• Total Cost was 855.1 M$
• Percentage of AFE Spent was 83.2%
• Cumulative Oil Production was 12,820 BO
• Cumulative Net Oil Sales were 1,026 M$
• Payout was achieved in 34 days
• Daily Net Income was 25 M$/day
3. Economic Performance for the Program
Well AFE Cost (M$) Actual Cost (M$) Max Oil Rate (BOPD) Cum. Oil (BO)
BDC #150 120.2 105.5 69 1,390
BLD
CM #15 117.7 45.2 516 9,400
CM #212 315.1 407.0 30 30
CM #313 349.6 210.0 52 1,000
CM #339 125.0 87.4 63 1,000
∑ Program 1,027.5 855.1 730 12,820
NOTE - All Cumulative values presented are as of 1/5/14.
4. Project Details – BDC #150
TTWO – Perf Addition; TT GPK Screen Hangoff
• Project Payout = 36 days
• Spent AFE = 87.8%
• 42 BOPD, 339 MCFPD, 524 BWPD, (current stabilized rate)
• Project Duration was 1 day over the AFE timeline estimate due to high winds and poor weather
conditions
• Np = 1,390 BO
• The first lesson learned from this project was to plan for weather contingency downtime days when
conducting workover operations in the fourth quarter of the year in the SELA area.
• The second lesson learned from this project was that a thru-tubing hang-off screen assembly
deployed in the end of tubing above the perfs was an effective sand control method based on the
production performance.
5. Project Details – BLD CM #15
TTRC – Natrural Completion: e-line TT preforator
• Project Payout = 3 days
• Spent AFE = 38.4%
• 219 BOPD, 67 MCFPD, 0 BWPD, (current stabilized rate)
• Project Duration was on schedule with the AFE timeline estimate
• Np = 9,400 BO
• The main lesson learned from this project was that we have an analog
that illustrates that we can produce a well from 6300’ as a natural
completion using controlled rate (small choke size ≈14/64”) for sustained
cumulative production value of over 60 producing days (Np = 9400 BO).
6. Project Details – CM #212
TTGPK RC – e-line/slickline & pump only operation
• The project will most likely never pay out since the well appears to be producing
from a slightly depleted water swept sand!
• Spent AFE = 129.2%
• 0 BOPD, 228 MCFPD, 20 BWPD, (current stabilized rate)
• Project Duration was 13 days over the AFE timeline estimate due to high winds and poor weather conditions and
Challenging well conditions.
• Np = 30 BO
• The team plans to further evaluate the reservoir performance of this project and to gain an understanding of why
this project failed to provide the production that was planned.
• The first lesson learned from this project was to plan for weather contingency downtime days when conducting
workover operations in the fourth quarter of the year in the SELA area.
• The second lesson learned from this project was that reservoir’s in the 3100’MD depth range are capable of
accepting a sand control treatment at 500 #/ft-perforation of sand being deployed in the formation without a
screen out in a slightly pressure depleted water swept reservoir.
7. Project Details – CM #212
TTGPK RC – project challenges
• High winds and poor weather conditions
• Gravel pack sand volume pumped was 25X job planned volume
• DW plug failed to set and function properly twice
• Umbrella plug setting issues requiring slickline fishing.
8. Project Details – CM #313
TTGPK RC – e-line/slickline & pump only operation
• Estimated Project Payout = 61 days
• Spent AFE = 60.1%
• 52 BOPD, 50 MCFPD, 9 BWPD (current stabilized rate)
• Project Duration was 2 days over the AFE timeline estimate due to high winds and poor weather
conditions
• Np = 1,000 BO
• The main lesson learned from this project was that the team was able to execute a thru-tubing
gravel-packed recompletion without using Coiled Tubing as a component of the recompletion
operation using only a pump spread and wireline spread to execute this job for 210 M$. This
operation represents about a 125 M$ savings as compared to the coiled tubing thru-tubing
gravel-packed method.
• The second lesson learned from this project was to plan for weather contingency downtime days
when conducting workover operations in the fourth quarter of the year in the SELA area.
9. Project Details – CM #339
TTRC – Natrural Completion: e-line TT preforator
• Estimated Project Payout = 30 days
• Spent AFE = 69.9%
• 44 BOPD, 100 MCFPD, 4 BWPD (current stabilized rate)
• Project Duration was 4 days over the AFE timeline estimate due to high winds and poor weather conditions and
tubing restrictions caused by scaling of tubulars.
• Np = 1,000 BO
• The first lesson learned from this project was to plan for additional slickline work days for the mitigation of scale on
the wall of the production tubing and completion hardware in the wellbore when working in the SELA area
• The second lesson learned from this project was that we have an analog that illustrates that we can produce a
well from 3000’ as a natural completion using a controlled rate for sustained cumulative production value of
over 60 producing days (Np = 1000 BO); furthermore the well is still producing without sand production issues.
• The third lesson learned from this project was to plan for weather contingency downtime days when conducting
workover operations in the fourth quarter of the year in the SELA area.