Thriving in a Lower for Longer Environment - Mary Van Domelen
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Thriving in a Lower for Longer Environment - Mary Van Domelen
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Thriving in a Lower for Longer Environment - Mary Van Domelen
- 1. Primary funding is provided by The SPE Foundation through member donations and a contribution from Offshore Europe The Society is grateful to those companies that allow their professionals to serve as lecturers Additional support provided by AIME Society of Petroleum Engineers Distinguished Lecturer Program www.spe.org/dl
- 2. Society of Petroleum Engineers Distinguished Lecturer Program www.spe.org/dl Mary Van Domelen, PE, SPEC January 2020 Tour Thriving in a Lower for Longer Environment
- 3. Lecture Format • The challenge • Market dynamics • Keys to success • Impact of technology • Takeaway points 3
- 4. Unconventional Resources Development Hydraulically Fractured Horizontal Wells Image source: Colorado School of Mines 4
- 5. Major US Basins and Shale Plays Basins Gas Plays Oil/Liquid Plays Image source: PacWest Consulting Partners (2016) 5
- 6. North American Basins and Shale Plays Image source: PacWest Consulting Partners (2016) 6 Basins Gas Plays Oil/Liquid Plays
- 7. The Challenge • In 2014, the price of West Texas Intermediate (WTI) started to drop, reaching a low of $26 per barrel in February 2016. • Industry analysts predicted that unconventional shale plays would be shut down as they would no longer be economical. • The shale industry did not just survive: It thrived….How? 7
- 8. US Oil Production Growth West Texas Intermediate (WTI) Price Data source: macrotrends.net WTIPrice($/bbl) USOilProduction(1000bbls/day) 8 $107 $26 $114
- 9. US Tight Oil Production by Play Source: US Energy Information Agency 9
- 10. US Shale Gas Production by Play Source: US Energy Information Agency 10
- 11. Wellhead Breakeven Prices 2013 2014 2015 2016 2017 2018 Source: Rystad Energy NASWellCube US$/bbl Bakken ($29/bbl) Eagle Ford ($38/bbl) Niobrara ($34/bbl) Permian Delaware ($39/bbl) Permian Midland ($33/bbl) 11 ~ $90 - $110/bbl ~ $30 - $40/bbl
- 12. Profitability vs. Breakeven Data source: Federal Reserve Bank of Dallas (March 2019) 12 Breakeven EIA Forecast
- 13. WTI and Brent Crude Oil Price predictions ($/bbl)
- 14. Oil and Gas Extraction Workers US Oil Production Data source: US Bureau of Labor Statistics (August 2019) ~80 Bo/day/person ~45 Bo/day/person US E&P Company Employees (x 1,000) 14
- 15. Shifting Landscape of Business Drivers Improve ROI (Return on Investment) Decrease Costs Increase Production Reduce Cycle Times ɣ + Expansion Land Grab (2009-2011) Production Growth (2012-2014) Capital Discipline (2015-2017) Return on Investment (2018-2020) 15
- 16. Generating Free Cash Flow • Longer laterals • Optimized completions • Proactive artificial lift designs Increase Production • Services and materials pricing • Decrease cycle time • Optimize processes Reduce Cost of Supply 16
- 17. Composite Well Cost Index Date Oil Price Cost Index 2Q-2011 $114 1.07 2019 ~ $60 0.86 Data source: Spears and Associates, Inc (4Q-2018) • Oil prices dropped ~50% • Well costs reduced only ~20% 17
- 18. Breakdown of Total Well Costs Typical horizontal shale well 18 50% 30% 20%
- 19. Drilling’s Contributions to Improved ROI Improve ROI Decrease Costs Increase Production Improve Cycle Times ɣ + 1) Increased lateral lengths 2) Reduced drilling times 3) Pad drilling 19
- 20. 20 Increasing Lateral Lengths by Play LateralLength(ft)
- 21. Lateral Length Distributions - 2018 21
- 22. Significantly Reduced Drilling Times 22 23 8.3 days 46 32 days 26 22 days 17 12 days
- 23. New-well Oil Production per Rig Bakken Play Source: EIA Drilling Productivity Report (October 2019) 23
- 24. Drilling Efficiency Gains Technology + Teamwork Technology Advances • Formation specific bits • Improved stator designs • Better, more reliable, data while drilling lateral • Geo-steering software • Auto-drilling software Teamwork • Consolidated work force • Empowerment of the field • Common goals, improved communication • Shared data to accelerate learning curve • Performance analytics 24
- 25. Multi-Well Pad Drilling Source: ConocoPhillips Eagle Ford Investor Tour https://www.youtube.com/embed/w5R3FqwJ8oI?rel=0 25
- 26. Multi-Well Pad Drilling Trends Source: Spears and Associates Insider (June 2019) 26
- 27. Pros and Cons of Multi-Well Pad Drilling Advantages • Reduced surface footprint • Fewer rig moves – Saves 2-4 days – Reduced exposure to personnel • Batch drill wellbore sections – Allows offline cementing operations – Reduced mud swaps – Less laying down of pipe • Focus on “hidden” inefficiencies Challenges • More complex wellbores – Anti-collision considerations – Longer step-outs • Concentrated/increased traffic • Simultaneous operations – Multiple rigs on larger pads – Drilling and completion simops • Long lead time bringing wells onto production 27
- 28. Multi-Well Pad Completion Source: ConocoPhillips Eagle Ford Investor Tour https://www.youtube.com/embed/w5R3FqwJ8oI?rel=0 28
- 29. Completion Phases Horizontal wells with multi-stage hydraulic fractures 1. Run and cement the lateral liner (or isolate with casing packers) 2. Hydraulically fracture the lateral stage by stage a) Fracture first stage b) Use wireline to pump down frac plug and perforating guns • Set frac plug to isolate prior stage • Pull up, perforate, pull out of hole c) Fracture next stage – repeat process 3. Drill out frac plugs with coiled tubing (or workover rig) 4. Flowback to recover frac fluids and debris from the wellbore 29
- 30. Completions Impact on Profitability Improve ROI Decrease Costs Increase Production Reduce Cycle Times ɣ + 30
- 31. Enhanced Completions Drive improved well performance Source: Rystad Energy NASWellCube (February 2018) 2014 First year oil decline curves for horizontal wells by production start yearBarrelsofOilperMonth Midland Delaware Eagle Ford Bakken 2017-2018 2011 2016 31
- 32. Increased Well Productivity Expands the economic footprint Early Bakken Development New Fairway Periphery 32 Montana North Dakota
- 33. Trends in Completion Design Parameters 33 Completion Design Parameters • Lateral length • Stage count • Proppant mass • Fluid volume • Injection rate • Cluster/perforation design • Well spacing SPE 194345 “Trends in the North American Frac Industry: Invention through the Shale Revolution” Lateral Length (ft) Stages Proppant (lbs) Fluid (bbls) Rate (BPM)
- 34. Evolution of Stage and Cluster Spacing ~ 450 ft Stage Spacing 2011 - 2012 4,500 ft lateral 8-10 stages 2016 - 2017 10,000 ft lateral 60-70 stages ~ 225 – 350 ft ~ 225 ft – 350 ft • Current trend is to increase stage spacing while reducing cluster spacings - 28 to 45 stages with as many as 10-15 clusters (10,000 ft lateral) • This provides significant cost and time savings, without sacrificing production results 34 ~ 150 ft ~150 ft ~150 ft
- 35. Optimizing Frac Designs Utilizing completion metrics 180-dayOil(bbl/ft) Proppant per Lateral Length (lb/ft) ? ? Middle Bakken Three Forks How would you interpret this data? 35
- 36. Move from Enhanced to Optimized Bigger is not always better Upper Bakken Shale Lower Bakken Shale Middle Bakken Three Forks 36
- 37. Middle Bakken to Three Forks Communication SPE 199735 Leveraging Cloud-based Analytics in Active Well Defense Projects and Automated Pressure Response Analyses Fracture Driven Interaction Initiates Offset Well Pressure 37
- 38. Completion Multivariate Analysis Central Bakken Example Williston Middle Bakken Three Forks 1 Three Forks 2 Three Forks 3 38 Reference SPE 184851 or SPE 187254 for Analysis Technique
- 39. Combine Physical and Statistical Models Stage spacing transformation y = 10.05*ln(x) + 70.908 Proppant mass transformation y = 5.9451*ln(x) – 15.010 Completion Design Parameter Coefficient Transformed ft/stage 0.4440 Transformed lb/ft 0.5320 Adjusted 180-day Water Cut -0.1576 Hydrocarbon Pore Volume 1.2637 Completion Technique 1.8173 Maximum Injection Rate 0.0311 Gross Interval Thickness 0.0943 Ave Prop Conc (ppg) -9.5170 39 ActualProduction365–dayBo Model Prediction 365-day Bo Reference: SPE 184851 or SPE 187254 for Analysis Technique
- 40. Optimizing Well Performance Develop formation specific best practices • Leverage basin completion & production metrics • Identify key completion parameters • Combine statistical analysis with physical models • Move from enhanced to optimized completions Recognize that completion design must be integrally linked to development plans 40 Image source: Seven Generations Energy Investor Day Presentation January 2019
- 41. Completion Cost Breakdown Bakken 10,000 ft lateral example 41 ~65% ~20% 40% 20% 10% 10% 10% 5% 5%
- 42. Game Changer Technologies 1) Cloud technology, data analytics, and machine learning 2) Regional sand and new sand delivery systems 3) Extreme limited entry (XLE) perforating 4) High viscosity friction reducers (HVFR) 5) Produced water recycling 6) Wireline operations and frac plug improvements 7) Coiled tubing drill-outs 42
- 43. Traditional Frac Stage & Well Files Printed fracture treatment plot with hand- written annotations about the operations Paper copies of stage reports Multiple USBs 43Source: SPE 197105 Leveraging Cloud-Based Analytics to Enhance Near-Real Time Stage Management
- 44. Utilizing Cloud-based Technologies • High frequency (1-sec) fracturing data is collected throughout the entire completion • As received, the files are poorly structured and difficult to manipulate • Cloud-based storage makes stage data readily available, allowing rapid visualization and analytics 4-way zipper, entire operation, 13 days Closer evaluation, 5-day timespan 44
- 45. Machine Learning (ML) Applications Auto-flagging fracturing events Start Time End Time ISIP Breakdown Pressure Test 45 Ball Seat
- 46. ML Illustration: Auto-picking ISIP Pumping Yes/No 46 Water Hammer Instantaneous Shut-in Pressure
- 47. Combining Frac and Geology Data Possible with cloud-based technologies • Each frac stage is an “investigation” into the unique geology along a specific section of the lateral 47 Average Pressure ISIP Pressure
- 48. Driving Down Frac Sand Costs 48 Northern White Sand Brown or Brady Source: Rystad Energy 1) Transport and storage 2) Self-sourcing 3) Regional sand 4) Mine ownership
- 49. Sand Management Program Case Study: Chesapeake Energy Northern White Sands 49 Reference: Oil and Gas Investor (August 2019) Statistics ~ 8 billion pounds per year ~ $100 million savings ~ 92% reduction in sand NPT Program • First trials in 2013 • Mid-2018 initiated full program • Team of 2 to manage • Hybrid strategy CHK operations Regional sand supply Traditional NWS
- 50. Facture Initiation Points Increasing cluster efficiency 50 Poor Cluster Efficiency Offset Parent Well Offset Parent Well
- 51. Increasing Cluster Efficiency Dynamic diversion 1) Ball sealers, perf pac balls 2) Degradable particulates 3) Perf pods 4) Limited entry perforating 5) Extreme limited entry (XLE) 51
- 52. Three Forks to Three Forks Diversion Triggering Frac Hit Fracture Driven Interaction Initiates
- 53. Extreme Limited Entry (XLE) Cost effective method to increase cluster efficiency 53 Design Criteria Limited Entry Extreme Limited Entry Perforation Friction 1,000 - 1,500 psi 2,000 – 4,000 psi Rate per Perforation 2 – 3 BPM/Perf 4 – 6 BPM/Perf Recommended references: SPE 179124 (2016), SPE 184834 (2017), SPE 189880 (2018) and SPE 194334 (2019)
- 54. High Viscosity Friction Reducers (HVFR) Primary application – replace hybrid systems Hybrid system requirements • Guar gelling agent • Low pH buffer • High pH buffer • Crosslinker • Rapid kill biocide • Fresh (or relatively fresh) water • Hydration unit on location HVFR – simplified operations • One chemical • Less stringent water quality • Reduced equipment footprint – No hydration unit – No chemical trailer required – Fewer liquid additive pumps ~30% reduction in fluid system costs 54
- 55. High Viscosity Friction Reducers (HVFR) Primary application – replace hybrid systems Hybrid system requirements • Guar gelling agent • Low pH buffer • High pH buffer • Crosslinker • Rapid kill biocide • Fresh (or relatively fresh) water • Hydration unit on location HVFR – simplified operations • One chemical • Less stringent water quality • Reduced equipment footprint – No hydration unit – No chemical trailer required – Fewer liquid additive pumps ~30% reduction in fluid system costs 55
- 56. High Viscosity Friction Reducers (HVFR) Reduced costs with higher performance • Higher proppant concentrations • Reduced water volumes • Lower friction pressures • Better proppant transport • >90% regained permeability 56 HVFR
- 57. Produced Water Recycling Considerations • Availability of fresh water • Quality of produced water • Water transfer options • Central storage Source: Texas Water Development Board, December 2018 Aquifer Levels in Texas Remediating for entrained oil and for solids 57
- 58. Produced Water Recycling Facilities Components • Produced water storage • Skim or flocculation • Treatment to remove organics • Underground water transfer pipelines Economic Benefits (Oklahoma Example) • Low OPEX ~ $0.30-$0.50/bbl • Facilities generate revenue • Minimizes saltwater disposal • 30% reduction in freshwater consumption 10,000 bbl/day Recycling Capacity and 500,000 bbl Useable Storage Temporary Recycling Facilities • No CAPEX required • OPEX $2.50-$4.00/bbl depending upon water quality 58
- 59. Data Mining Water Management Combined intelligence • Satellite imagery analytics • Government databases • Market research • Internet of things (IoT) sensors Provides insight into available water for purchase, transportation infrastructure, and disposal options Source: North America Shale Magazine (September 2019) 59
- 60. Wireline Operations Multi-well zipper completions 60 Source: ConocoPhillips Eagle Ford Investor Tour https://www.youtube.com/embed/w5R3FqwJ8oI?rel=0
- 61. Wireline Operations Reduce interstage time with quick connect systems Standard operations • 20 to 30-minute well swaps Quick connect systems • 10 to 12-minute well swaps 61
- 62. Evolution of Composite Frac Plugs Supplier competition = innovative designs • Better composite materials • Ceramic buttons and powdered metal for slips (previously cast iron) • Ability to run balls on seats, caged balls, or flappers to isolate the plug • Smaller OD => faster run in speed and less likely to get hung up • Shorter => less material to mill and circulate out of the well
- 63. Coiled Tubing Operations Significant efficiency gains • Move toward large diameter coiled tubing (CT) units – Reach extended to ~23,000 ft • Better understanding of debris transport – HVFR technology replacing gel pills – Elimination of short trips • Typical performance – Drill out entire lateral in a single day (30-50 frac plugs) – Wells on production 2-3 days faster 63
- 64. Coiled Tubing Operations Significant efficiency gains 64 • Live seminar 2/6/2020 @ 8:30 am CST • Reference SPE 187337
- 65. Artificial Lift and Production Facilities Production enhancement and cost reduction Expansion Land Grab (2009-2011) Production Growth (2012-2014) Capital Discipline (2015-2017) Return on Investment (2018-2020) 65 Flow well until it dies, install rod pumps Two stage lift program to accelerate production Modular flow back facilities to reduce CAPEX Centralized facilities reduce LOE
- 66. Takeways • Collapse of oil price did not stall the growth of shale oil production • We are a lean industry – capable of producing more with less • Drilling efficiencies are high, but lateral lengths are still increasing • Optimized completion designs deliver economic well productivity • Game changer technologies have reduced completion costs and increased operational efficiencies 66
- 67. Society of Petroleum Engineers Distinguished Lecturer Program www.spe.org/dl 67 Your Feedback is Important Enter your section in the DL Evaluation Contest by completing the evaluation form for this presentation Visit SPE.org/dl
Editor's Notes
- Before we get started, I would like to thank the SPE Foundation, Offshore Europe, and AIME (American Institute of Mining, Metallurgical and Petroleum Engineers) for supporting the Distinguished Lecturer Program. I would also like to thank my managers at Well Data Labs, for allowing me to participate in the Distinguished Lecturer Program. And last, but certainly not least, I would like to thank the SPE Distinguished Lecturer staff for all they do to make the DL program a success. It is truly an honor to be here today.
- The topic of my lecture is “Thriving in a Lower for Longer (Oil Price) Environment.” Nominations for the 2019-2020 Distinguished Lecturer season closed at the end of March 2018. After that, there were 3 rounds of qualifications, finishing at the 2018 SPE ATCE, with notification of final acceptance in October 2018. The first tours for the 2019-2020 season start in September 2019; 18 months after the process began. During this time frame, the WTI price has fluctuated from a high of $76.41 (10/3/2018) to a low of $42.53 (12/24/18). We’ve come to realize that not only will the oil price remain “lower for longer” but significant price fluctuations may be the norm moving forward.
- The format for my lecture will be as follows. I will introduce the challenges, review the market dynamics, discuss the keys to success, and highlight the most impactive game changing completion technologies. I will wrap up with the takeaway point - which is, in short – the importance of leveraging technology to drive operational efficiencies and reduce operating costs. This is particularly important today, where a $5/bbl fluctuation in oil price can be the difference between realizing a profit or posting a loss. While my examples are based upon shale plays, the behaviors described apply to all types of petroleum developments.
- I will be working under the assumption that the audience has some familiarity with the processes used to drill and complete horizontal wells in unconventional plays. Horizontal well, multi-stage hydraulic fracturing 101 is as follows. A vertical wellbore is drilled, protective pipe is run into the wellbore, and cemented into place. At the “kick-off point”, the drill path becomes horizontal – generally penetrating the formation for 1 to 2-miles; sometimes even farther. Casing is set, cemented or isolated with swell packers, and the lateral is broken into sections with multiple hydraulic fracturing treatments (frac stages) applied along the lateral. This process has the distinct advantage of generating significantly more reservoir contact that is possible with a vertical completion as you see on the right side of the slide.
- This slide shows the major petroleum basins in the lower 48 United States with active and potential unconventional oil and gas plays overlaid. The first of the gas plays was the Barnett, located in north central Texas. The first of the oil plays was the Bakken, located in the Williston Basin of western North Dakota and eastern Montana. You will note that the Permian Basin, which is split into the Midland and Delaware Basin, is relatively small in areal extent compared to Marcellus in the Appalachian Basin.
- This slide shows the major petroleum basins in the US and Canada with active and potential unconventional oil and gas plays overlaid. The first of the gas plays was the Barnett, located in north central Texas. The first of the oil plays was the Bakken, located in the Williston Basin of western North Dakota and eastern Montana – extending into Canada.
- In 2014, the price of West Texas Intermediate (WTI) started to drop, reaching a low of $26 per barrel in February 2016. Industry analysts predicted that unconventional shale plays would be shut down as they would no longer be economical. The shale industry did not just survive: It thrived….How? Now, you may argue that our industry has not thrived. For sure, the past 4 years have been very difficult – especially for the service sector. My claim that the industry has thrived is based upon the unprecedented increase in oil production combined with the ability of the better manager companies to operate cash neutral. Today, there are a growing number of companies which are achieving acceptably levels of profitability.
- *** Use this slide to define “Lower for Longer” price environment. *** This slide show the 10-year historical price for West Texas Intermediate (WTI). The 10-year high was $113.93 on 4/29/2011. The 2014 high was $106.92 on 6/20/2014 and the 10-year low was $26.21 on 2/11/2016. Most analysts agree that the highest probability for the future average WTI price is in the range of $55-65/bbl with price swings of +/- $5/bbl in either direction. This is what I consider a “lower for longer” price environment. I have overlaid the US Oil production (in 1000 bbls/day) over the 10-year historical WTI price. Although the WTI oil prices have not returned to pre-2014 levels, US production continues to grow significantly. The majority of the production growth is from unconventional reservoirs.
- This is the US tight oil production growth by play.
- This is the US shale gas production growth by play.
- Let’s look at wellhead breakeven prices. The wellhead breakeven price for US shales varies by play and, in fact, will vary within that play. This chart shows the evolution of the average breakeven prices for 5 of the major US shale oil plays from 2013 to 2018. Breakeven prices have dropped from ~$65-$100/bbl down to ~$30-$40/bbl. Prices have remained relatively flat through mid-2019.
- Operating at breakeven is different than operating a company to make money. Each quarter, the Federal Reserve Bank of Dallas performs an energy survey. This year, they ask 123 E&P companies the question “In the top two areas in which your firm is active: What WTI oil price does your firm need to profitably drill a new well”. Note that the definition of profitably may, and most likely does, vary from company to company. On the previous slide, I showed you that the average breakeven prices are in the range of $30-40/bbl. On this slide, we see that the average WTI price which would be required for an E&P company to ramp up their drilling program is in the range of $48-$54/bbl. In the U.S. Energy Information Administration’s (EIA) January Short-Term Energy Outlook (STEO), EIA forecasts that the West Texas Intermediate (WTI) spot price will average $59/b in 2020 and $62/b in 2021. EIA forecasts that crude oil prices will remain elevated in the first few months of 2020, reflecting a price premium on crude oil from recent geopolitical events. However, this price premium will diminish in the first half of 2020 and market fundamentals will drive the crude oil price forecast in the second half of 2020 and in 2021.
- In the U.S. Energy Information Administration’s (EIA) January Short-Term Energy Outlook (STEO), EIA forecasts that the Brent crude oil spot price will average $65 per barrel (b) in 2020 and $68/b in 2021 (Figure 1). EIA forecasts that the West Texas Intermediate (WTI) spot price will average $59/b in 2020 and $62/b in 2021. EIA forecasts that crude oil prices will remain elevated in the first few months of 2020, reflecting a price premium on crude oil from recent geopolitical events. However, this price premium will diminish in the first half of 2020 and market fundamentals will drive the crude oil price forecast in the second half of 2020 and in 2021.
- This slide is one that I really believe illustrates the nature of the people in our industry. This is data from the US Bureau of Labor Statistics for the Oil and Gas Extraction Sub-Sector. In 2014, at the peak of oil prices, there were nearly 200,000 people working for E&P companies. This number does not include the people working for supporting roles, such as service companies, trucking companies, manufacturing companies, etc. In 2016, after the price crash, there were ~ 170,000 employees. Today (August 2019) there are even less. *** CLICK *** Now, let’s review what US oil production has done during the same time frame. *** CLICK *** On a per worker basis, E&P companies are nearly twice as efficient today (on a per bbl of oil produced per worker) compared to 2014. This is an illustration of how E&P companies have adjusted to “thrive in a lower for longer environment”.
- Let’s talk about the evolution of business practices over time. Prior to 2011, the US unconventional E&P companies were in the process of securing leases. Starting around 2012, and it varies a bit by play, most companies were aggressively increasing production, while adding significant debt to their balance sheets. After the price crash in 2014, companies started to exercise capital discipline – striving to be cash flow neutral. Today, the E&P companies are expected to provide an acceptable return on investment to their share holders – increase free cash flow. *** CLICK *** Let’s look at the simple formula for success, e.g., what allows a company to “Thrive in a Lower for Longer Environment”? In the simplest terms, the key is to increase production while decreasing costs and reducing cycle times.
- What we are hearing from Wall Street and private investors is the requirement to generate free cash flow – which is a metric for return on investment. To do this, we need to increase production (e.g. revenue) and reduce costs. The three methods used by most companies to increase production are to drill longer laterals, optimize the completion and adjust the artificial lift program to accelerate production. Regarding cost reductions, let’s talk about pricing first, and get it over with, because reductions in services and material pricing is only a portion of the formula for success. In fact, operators have pushed service companies as hard as is possible – at least in my opinion. I don’t believe that there are significant gains to be realized through contract negotiations. I apologize to any supply chain people in the audience – but the way forward is through technology and cooperation between the operators and service sector.
- 10-year high WTI price was $113.93 on 4/29/2011, 10-year low was $26.21 on 2/11/2016, Current price is $53.63 on 8/6/2019 Today, oil prices are about half of what they were at the high. However, composite well costs are only down 20-30%. Cost reductions alone can not account for the improvement in profitability
- This slide show the breakdown of the 3 major components of the capital expenditure for a fractured horizontal shale well. Drilling typically represents ~30% of the costs, although this percentage may be higher in areas where drilling is more difficult – for example the SCOOP/STACK play in Oklahoma. Completion costs are normally at least 50% of the total well costs. Production equipment and facilities make up the remainder of the well costs.
- Let’s return to our simple formula for success and talk about drilling’s contributions. The 4 main improvements over the past years has been the ability to continually increase lateral lengths, significantly reduce drilling times, the shift to pad drilling and in many basins, the adoption of slim hole well designs. Increasing lateral lengths will increase the production per well, due to more reservoir contact. Reducing drilling times not only decreases costs (since rigs are contracted on a per day basis) but it also reduces cycle times. Pad drilling not only reduces time and costs during the drilling phases of a well, but later we will talk about the impact on completion costs and cycle times. Slim hole well designs reduce drilling costs and also improve the efficiencies during the drill out phase of well completions.
- This slide shows the increase in average lateral length for the major US shale plays. I combined data from various sources. I did note some inconsistencies from source to source. However, all data sets showed increasing lateral lengths with time and all basins are trending toward an average of ~10,000 ft.
- Across all plays, drilling times for horizontal shale wells have been significantly reduced. In some cases, wells are being drilled at rates above what was considered to be the technical limit just a few years ago. The figures in this slide show the various ways that companies are demonstrating their improvement.
- Not only are we drilling wells faster, but the productivity per well is increasing. This data is taken from the Energy Information Agency (EIA) monthly drilling productivity report. It shows that the new-well oil production per rig has increased from ~400 bbls/day in 2014 (before the oil price collapse) to ~1500 bbl/day in October 2019. This is nearly a 4-fold increase! Because lateral lengths have been relatively constant in the Bakken during this time frame, the increase is productivity is due to reduced cycle times and improved completion practices. Notes: The Drilling Productivity Report uses recent data on the total number of drilling rigs in operation along with estimates of drilling productivity and estimated changes in production from existing oil and natural gas wells to provide estimated changes in oil and natural gas production for seven key regions. EIA's approach does not distinguish between oil-directed rigs and gas-directed rigs because once a well is completed it may produce both oil and gas; more than half of the wells produce both.
- Pad drilling had been a major enabler for improved drilling efficiencies. This picture shows a multi-well pad with 2 drilling rigs operating in the Eagle Ford. If you are not familiar with horizontal well drilling practices, I highly recommend the video referenced in the link below the photo. You can Google “ConocoPhillips Eagle Ford Investor Tour” video and find it.
- The tend toward pad drilling varies by play. This graph shows the largest pads and the average pad size in the Bakken (blue lines) and Eagle Ford (orange/gold lines). One size does not fit all. The Eagle Ford has an average of two wells per pad going to 3, while the Bakken has 3 wells per pad going to 4. The Eagle Ford has an 8 wells per pad maximum while the Bakken is 17. (I know that there are larger pads in the Bakken, but the data isn’t public yet) Notes from Spears: Other regions show a more stable average, which is generally 2-3. The big change is this, however: Those big pads with lots of wells? Most regions are seeing those big 10-20 well pads shrinking. We think that oil companies are finding that a 25-well pad that takes a year to drill and then frac and then bring on line ties up too much capital for shareholders to be happy. With cash flow as king, we are looking for oil companies to hurry up the time from spud to first oil on each pad… and that probably means 3-4 wells per pad. This impacts drilling rig contracts, directional contracts, frac contracts, water contracts, sand contracts, coiled tubing…
- Typical full rig move time, from pad to pad takes 2-4 days “Hidden” inefficiencies – e.g. connection times
- Let’s talk about completions now. This photo is from the same video which I recommended earlier. If you are not familiar with the completions, this video provides a great overview of the pad completion process.
- Here are the basic phases of a completion. Once the lateral is drilled to TD, the liner is run and cemented. In some cases, swell or mechanical packers are use for isolation of the liner. The first stage, generally called the toe stage, is fractured. After that, wireline is used to pump down the plug to isolate the toe stage and guns to perforate the second stage. Once the perforations are shot, the wireline is pulled out of hole and the second stage is hydraulically fractured. This process is repeated 30 to as many as 70 times until the entire lateral has been fracture stimulated. After the last stage is fractured, a coiled tubing (CT) is brought to location and the CT is used to drill out the frac plugs. Once all the frac plugs have been drilled out, the CT is pulled out of the hole, and the CT unit is rigged down and moved off location (or to the next well on the pad). The well then flowed to a special flow back spread to recover the frac fluids and remove debris from the wellfore.
- Let’s return to our simple formula for success and talk about completion’s contribution to the economic success of a development. For the reservoir engineers in the audience, when I joined Continental Resources in 2013 years ago, the “Blended Average” EUR type curve was 603 MBoe. By 2018 the average EUR type curve nearly doubled to 1100 MBoe. (reference
- This slide shows the first-year type curves for 4 major oil basins. You can see that there have been significant improvements in well completions from 2011 through 2018. The increased well productivities are a result of the introduction of “enhanced completion” practices. From 2017 forward, the “blended average” type curve for most plays has remained about the same. This is because many operators are moving out of the core areas. It still possible to make economic wells in the lower quality areas by utilizing the appropriate completion practices.
- This slide will illustrate the impact of “enhanced” completions designs and how the new completion technologies have expanded the economic footprint of the Williston Basin. This map shows the Bakken play. The different colored areas are different reservoir domains, e.g. areas of different reservoir quality. Early development was limited to the Elm Coulee (east) and Parshall (west) fields as these areas have higher matrix permeability and more abundant natural fractures. The black outline represents the initial areas targeted for development with enhanced completions. ****CLICK**** Through the development of “enhanced” completion practices, highly economic wells were drilled and completed in the central areas – public data bases refer to this as the “New Fairway”. Most recently, companies are announcing economic wells completed in the north and south “Periphery”. These wells are not as prolific as in the New Fairway, but smaller “optimized” completions allow the well costs to be reduced sufficiently to make the wells economic, even though the actual production rates are lower in the Periphery.
- This slide shows the trends for the most impactive completion design parameters over the past 7 years, for several of the major shale plays. I realize that the plots are difficult to read, so I will refer you to the SPE paper. You can also find summaries of the data in several recent trade journals. Let me give you an example of the changes that have occurred in the Bakken during this time frame. Lateral length ha been constant at ~10,000 ft (red curves – Middle Bakken and Three Forks). I worked the Bakken for 5 years (2013-2018). When I started the average stage count was 30, in 2018 the average stage count was 65. The proppant mass, or intensity (lb/ft) increased from ~300 lb/ft to ~12,000 lb/ft. Fluid intensity increased from ~8 bbl/ft to ~40 bbl/ft. Injection rates were increased from 30 BOM to 80-90 BPM. ***CLICK*** Today the trend is toward slightly smaller “optimized” completions and companies are testing various cluster/perforation designs, as well as, studying the relationship between completion design and well spacing NOTE: Summaries appear in July 2019 JPT and August 2019 American Oil and Gas Reporter
- Let’s talk a bit out optimizing frac designs. The best design varies by play, formation and even within areas of the same play. The primary completion metrics are what I showed you earlier: proppant intensity, fluid intensity, stage spacing, and injection rate. For any of these parameters, it is possible to construct a plot similar to what you see here. This particular plot shows the 180-day oil production, normalized on a per foot basis, verses the proppant intensity in lbs/ft. How would you interpret this data? ***CLICK*** More is better, correct? That is what we though for several years. ***CLICK*** As it turns out there is an optimum based upon the formation characteristics. Beyond that point, it is a waste of money to pump larger and larger completions.
- Here is a Williston Basin example. In this play, there are two productive zones: the Middle Bakken and the Three Forks. The source rock is the Upper and Lower Bakken Shales. The Three Forks formation has a higher water saturation than the Middle Bakken, and in some areas, is wet. The Lower Bakken Shale varies in thickness across the basin. In areas where the LBS is thin, and the TF has high water saturation, pumping too large of a frac has detrimental effects on the ROI due to drastically increasing water cut (production).
- I would like to show you a completion analysis case study. In this study consists of 992 wells with first production between 1-1-12 and 3-31-18 (minimum 18 months production) located in T124-153N and R95-98W, North Dakota, Williston Basin.
- With multiple completion parameters, how does an engineer optimize a completion? A multivariate analysis is required. The best analyses combine physical and statistical models. ***CLICK*** The topic of multivariate analyses is a lecture in itself. For our purposes, I will simplify the process. The concept is to use a large data base with geology, reservoir, drilling, completion and production metrics - ”Big Data” - along with a multivariate (multiple variables) statistical analysis to identify the critical parameters. In this example, the stage spacing and proppant mass are the key completion parameters and water cut and hydrocarbon pore volume are the most important reservoir properties. ***CLICK*** The next step is to develop the mathematical relationship between the key parameters and well performance. The term “transformation” indicates that the statistical analysis has been combined with a physical model, in this case a 3-D hydraulic fracture design program, which constrains the statistical model. In other words, the limitations of the physical system are accounted for. ***CLICK*** At this point, we can develop a mathematical model which describes the relative impact of each of the individual parameters. ***CLICK*** The final step is to compare the model predictions with the actual production, to ensure that an acceptable accuracy was achieved. If indeed acceptable, the model can then be used to optimize the completion in different areas of the play, accounting for the local geological and reservoir conditions. It is now possible to optimize based upon economic rate of return, not just maximizing production at any cost.
- Let’s look at the components of the completion costs. The largest is fracturing services. This is the cost of the frac equipment on location, how hard it needs to work (pressure, rate), man-power to run the equipment, and how long the completion takes e.g. hhp-hr. Frac services, combined with chemicals and proppants, (blue) generally accounts for ~65% of the total completion costs. The actual percentage will vary from basin to basin. In this example, the “all in” water costs are relatively low ~$3/bbl. In other plays, “all in” water costs can be as high as $8/bbl. Variable costs (green) directly related to stage count are wireline and coiled tubing products and services. In this example, the two represent ~20% of the total completion costs.
- Now I would like to talk about, what I believe, are the key game changer technologies that have significantly reduced completion costs and increased operational efficiencies. Because today’s lecture is shorter compared to other lectures on my schedule, I will only have time to cover 4 of the 7 technologies. If you are interested, I can leave copies of my slides which cover all 7 of the technologies.
- Important analyses Stage-to-stage comparisons Tracking operational efficiency Materials optimization Diverter effectiveness Screen-out avoidance Problem job analyses
- Engineers spend hours identifying events such as Breakdown and Instantaneous Shut-in Pressure (ISIP) in the time-series data that is generated.
- Notes from Permian Operator: Going to a regional sand vs. NWS has made the highest economical impact to our business with sand prices dropping from $130/ton to $20/ton, with some local spot prices at $10-$15/ton. The regional sand has not impacted production rates in the short term.
- Jason Pigott, EVP Operations and Technical Services, Chesapeake Energy: “We felt comfortable that regional sand in an area like the Eagle Ford was not going to be detrimental to our production. So that caused us the make the shift.”
- Ball sealers, or perf pac balls, were introduced in the early 1950’. While commonly used in traditional fracturing operations, never gained popularity in horizontal fracturing operations. The use of degradable polymers, most commonly polylactic acid (or PLA), was introduced to shale fracturing ~2010 but did not become widely used for about 5 years. There are two basic classes: ground particulates and clusters of fibers tied into knots, referred to as “perf pods” as they are delivered into the wellhead encapsulated in was-like pods (think plastic Easter Eggs that break open to reveal the contents and then dissolve). Limited entry perforating was first introduced in 1963 but was not believed to be applicable to shale fracturing until recently.
- References SPE 530 (Fracturing,1963) SPE 78318 (Acidizing, 2002) SPE 179124 (Shales, 2016) SPE 184834 (XLE, 2017) SPE 189880 (XLE, 2018) SPE 194334 (Evaluating LE, 2019)
- Mention that viscosities are a function of water quality, and that there are different systems available for waters with high TDS. Dissolved solids" refer to any minerals, salts, metals, cations or anions dissolved in water. Total dissolved solids (TDS) comprise inorganic salts (principally calcium, magnesium, potassium, sodium, bicarbonates, chlorides and sulfates) and some small amounts of organic matter that are dissolved in water. Calcium and magnesium dissolved in water are the two most common minerals that make water "hard." The hardness of water is referred to by three types of measurements: grains per gallon, milligrams per liter (mg/L), or parts per million (ppm).
- Mention that viscosities are a function of water quality, and that there are different systems available for waters with high TDS. Dissolved solids" refer to any minerals, salts, metals, cations or anions dissolved in water. Total dissolved solids (TDS) comprise inorganic salts (principally calcium, magnesium, potassium, sodium, bicarbonates, chlorides and sulfates) and some small amounts of organic matter that are dissolved in water. Calcium and magnesium dissolved in water are the two most common minerals that make water "hard." The hardness of water is referred to by three types of measurements: grains per gallon, milligrams per liter (mg/L), or parts per million (ppm).
- Mention that viscosities are a function of water quality, and that there are different systems available for waters with high TDS. Dissolved solids" refer to any minerals, salts, metals, cations or anions dissolved in water. Total dissolved solids (TDS) comprise inorganic salts (principally calcium, magnesium, potassium, sodium, bicarbonates, chlorides and sulfates) and some small amounts of organic matter that are dissolved in water. Calcium and magnesium dissolved in water are the two most common minerals that make water "hard." The hardness of water is referred to by three types of measurements: grains per gallon, milligrams per liter (mg/L), or parts per million (ppm).
- Permian Operator: Produced water and recycled water both have been a substantial economic hurdles to overcome. Both must be treated to kill bacteria, remove iron and recycled to provide ample water volumes for further completion development. By eliminating disposal fees, the operators and economically treat and reuse the same water numerous times. Drilling Info forecasts that $17.3 billion in water infrastructure investment will be needed in the Permian Basin by 2025 to sustain activity. The average slick water frac in the Permian used ~16 million gallons of water in 2018, compared to 4 million gallons in 2013. Produced water from the Permian grew from 37% to 48% of the national produced water from 2014 to 2018. (Oil and Gas Investor, August 2019) For every barrel of oil produced in the Permian, 4 to 10 bbls of water are produced. (Houston Chronical,
- Oklahoma Note: Temporary recycling facilities are available which do not require CAPEX: OPEX is $2.50-$3.60/bbl, depending upon produced water quality
- Modular flow back facilities Allows production facilities to be designed for life of well Two stage lift program accelerates production Electric submersible pumps, gas lift, or jet pumps (early time) Pumping units or hydraulic piston pumps (lower volume) Centralized facilities Preventative maintenance reduces failures More flexibility when take-away capacity is limited