INTERNATIONAL PERFORATING SYMPOSIUM 2014

Transcription

1 INTERNATIONAL PERFORATING SYMPOSIUM 2014 Completion evolution: The role of perforating in horizontal shale wells Kerry Daly, Global BD Manager- DST TCP WELL FLOW MANAGEMENT TM

2 Introduction The first horizontal well in unconventional shale was completed in 1981 Completion techniques were not fully proven until 2002 Since then, thousands of wells have been completed using two primary techniques: 1) Leaving the wellbore uncased across the formation and using open hole packers for isolation and fracsleeves for zonal access (OHMS) 2) Cementing casing in place and then perforating distinct sections of the wellbore for stimulation/ production purposes (CHPP) The technique chosen depends on: Wellbore parameters Client preferences Equipment availability and limitations Ultimate differentiators being: Cost reduction Productivity enhancement. Production data comparing the techniques is now available.

3 OHMS- Open Hole Multi-Stage system: Steps: 1. Surface or intermediate casing is placed in vertical section and cemented in place. 2. Casing is not emplaced across the horizontal, instead the OHMS consisting of fracsleeves and open hole packers is run and positioned with a liner hanger. 3. Pressuring up inflates packers and dropping balls isolates the sleeves, allowing stimulation into the formation at staged intervals. Optional systems allow for cementing in place where regulation requires. Benefits: No formation damage from cementing No interventions are required and fracking is continuous once started Thus saving time. Disadvantages: No perforations in the formation beyond mud infiltration zone or to initiate fracture. System costs may be substantially higher, limiting number of formation access points. Drives the decision to use the alternate CHPP method.

4 CHPP- Cased Hole Plug and Perf system: Steps: 1. Surface or intermediate casing is placed in vertical section and cemented in place. 2. Production casing is then run across the lateral and cemented, thus restricting flow into/ around casing. 3. Perforating with Tubing Conveyed (TCP) via tubing or coiled tubing (CT), or electric wireline via pump down or tractor, establishes contact with formation for stimulation/ production. Optional systems available: Toe Gun Casing Toe Sleeve CT TCP Plug and Perf(when screen-outs occur) 4. Fracking breaks down formation through perforations; stages isolated with composite plugs 5. Afterwards, production from all zones is established by milling up composite plugs. Benefits: Systems cheaper but take longer to complete, thus offsetting costs May be easier to rework in case of problems or when production drops. Disadvantages: Each intervention costs time, thus driving the decision to use the alternative OHMS.

5 CHPP TCP Toe Prep, via Coiled Tubing or standard Tubing: First operation after clean-out, no open perforations yet. Normally covers the first 500 ft. of wellbore > firing more clusters than previous Stages consist of 1-10 guns Gun lengths: 1-6 ft. long Gun OD: 2-3/4, 2-7/8, 3-1/8, 3-3/8 depending on casing size (4-1/2, 5 5-1/2 ) Gun Type: 6 SPF, 60 degree with DP or Super DP charges Guns typically not oriented, let pressure determine fracture path

6 CHPP- Toe Prep TCP- If Conveyed by Workover Rig: If Conveyed by Coiled Tubing (CT): Job Parameters: Cost: One or many pressure-activated firing heads fired at same time May or may not have time delays attached WL correlation not required, pipe tally used Packer normally not run Gun assemblies spaced out with tubing between, no length limitation Total trip time ~8-12 hours Rig ~$10,000/ day TCP ~ $15,000 Estimated total ~$25,000 Risk: If gun doesn t fire, lost time + additional trip on pipe required Drivers Job Parameters: Cost: One pressure-activated or ball-drop differential firing fires first gun Time delays between guns allow CT to move to next zone Number of guns and zones limited by surface lubricator length and crane height (~70 ft.) WL correlation not required, pipe tally used Total trip time ~6-10 hours CT unit ~$25,000/ day TCP ~ $15,000 Estimated total ~$35,000 Risk: If gun doesn t fire, lost time + additional trip on CT To reduce cost, new technology has been developed which requires no rig or CT.

7 CHPP-Alternative -To eliminate the cost of CT Toe Prep Casing Toe Gun Attached to outside of casing and run as part of casing string Run just above float collar/ shoe and cemented in place Requires larger borehole, which drives drilling cost Requires high-temperature explosives, more expensive Guns are downhole longer, risk leak at o-rings After the cement cures, pressure up to rupture disk or shear pins to fire gun To limit cement sheath at tool, must always bump wiper plug and follow with special fluid recipe. Removes Workover Rig/ CT costs and run time Creates limited perforations, usually maximum 10-ft. so entire toe is not prepped. Requires pressure pumping Requires subsequent WL pump down perforating Risk: If gun doesn t fire or unable to establish pump rate, must perform traditional TCP toe prep.

8 CHPP-Alternative - Becoming the System of Choice, Saves Two Coiled Tubing Runs. Casing Toe Sleeve Run just above float collar/ shoe and cemented in place After the cement cures, pressure up to rupture disk or shear pins Pressure shifts a sleeve, which opens ports to expose formation to fracpressure Optional fluid metering allows casing test prior to opening Safer option as no explosives used System Comparison Casing OD Tool OD Min. Borehole Removes Workover Rig/ CT costs and run time Doesn t create perforations, just access to formation Requires pressure pumping Requires subsequent WL pump down perforating Toe Gun 4-1/2 in. Toe Sleeve 4-1/2 in. Risk: If sleeve doesn t open or unable to establish pump rate, must perform traditional Toe Prep. To limit cement sheath at tool, must always bump wiper plug and follow with special fluid recipe in in. 8-1/4 in. 6-1/4 in.

9 CHPP-Fracparameters between runs - Regardless of how toe is perforated Frac Between Perforating Runs- Parameters: Perforations have established flow path Components of fracture (after perforation) Formation breaks down at ~10,000 psi (Eagle Ford) Fractures propagate best at ~ 100 bbl/min Bull head through the casing Allows higher pump-in rates

10 CHPP- Wireline(e-Line) Pump Down Wireline Plug & Perforation System Parameters: Run time is only 2-3 hours First set a Composite Frac Plug Then move up-hole to fire guns, 1-10 typically as Select-Fire with reverse polarity switches At end of run, circulate a ball into the Composite FracPlug This seals the zone below and allows fracturing through newly created perforations Risks: High failure rate Simplest failure: electrical short resulting in 4-6 hours lost time at ~$2,000/ hour standby. Most complex failure: parted line with live guns lost in hole resulting in 50 hours lost time. Rewards: Short operating time, limiting frac standby costs Unlimited stages can be performed Benefits far outweigh the risks! WL Pump-down Plug and Perf is the preferred method- not going away!

11 CHPP- Wireline(e-Line) Pump Down MENAPS Other Risks: Formation fails to break down If can t generate minimum 10 bbl/min, then cannot pump down WL guns If WL bridges out during pump down operations due to residual fill in casing Wellbore has not been reentered since frac event Necessary to run a TCP system to complete the stage Cost: WL Perforating~$10,000 per stage (additional cost of water not included) Estimated total ~$10,000 Operation: Set composite fracture plug, isolates previous stage Typically have residual pressure on wellbore: 1,000-4,000 psi Pressure control equipment required Requires high volume pumping to position guns, bbl/min Maximum running speed ~200 ft/min

12 Comparison- OHMS vs CHPP OHMS- Positives Negatives Multiple stages can be performed in a single trip Can be problematic if completion fails to get to depth No perforating or plug runs are required Inflexible- can skip a stage but can't add one No plugs must be drilled up Less productive because fractures cannot be oriented with maximum horizontal stress Takes much less time Complicated-hardware is not foolproof, and failures are difficult to resolve No guarantee that fracture will propagate opposite the open sleeve port-could be hundreds of feet up or down the well. In case of screen-out, cannot get Coiled Tubing past restrictions in ports- graduated drop ball systems Regulatory bodies are requiring cemented liners along with casing test- OHMS cannot provide Completion type and fracport locations must be planned well in advance Cost of equipment is high CCNP-Positives Negatives Easier to get to bottom Takes longer, but sometimes investment is worthwhile to get higher productivity More flexible-optimize frac in real time Future technology will allow 50+ stages of OHMS, leaving CCPP at a disadvantage Inexpensive due to a widespread availability of Higher frac costs due to standby in between stages equipment and crews 1

13 Comparison- Early Results Wells Completed before Comparison 1.2 Granite Wash Montney Early Industry Drivers: Lack of available equipment Lack of trained personnel High frac costs High coiled tubing costs High standby rates Ratio First shale completions: Used CCPP High costs/ high risk drove development of OHMS Time savings made these economical choice 0 Time Cost Production Time Cost Production OHMS PNP Costs have come down, so OHMS may not provide benefits it once did.

14 Comparison- New Techniques Wells Completed in 2013-Operator #1 3 Older Style: Sliding Sleeve Completion Annulus Free Fluid Between Packers Stages FracPorts per Stage Potential Entry Points New Style: Cemented Liner Completion Annulus Stages Perforation Clusters per Stage Potential Entry Points Cemented FracDesign: 4 Slick water (3 times more water) Increased Proppant(lb-ft)

15 Comparison- Later Results Wells Completed in 2013-Operator #1 3 Field Well Liner Style Completion 24-hr IP (BOEPD) Cost 1 1 Uncemented Sliding Sleeve 2,715 $8.23M 2 Cemented Plug& Perf 3,795 $8.23M 2 1 Uncemented Sliding Sleeve 884 $7.91M 2 Cemented Plug& Perf 1,348 $8.95M 3 1 Uncemented Sliding Sleeve 481 $7.04M 2 Cemented Plug& Perf 1,164 $7.00M 4 1 Uncemented Sliding Sleeve 563 $7.64M 2 Uncemented Sliding Sleeve 476 $8.24M 3 Cemented Plug& Perf 1,093 $6.96M 5 1 Uncemented Sliding Sleeve 1,888 $7.83M 2 Uncemented Sliding Sleeve 1,398 $7.76M 3 Cemented Plug& Perf 2,432 $7.76M Uncemented Sliding Sleeve Avg. 1,201 $7.81M Cemented Plug & Perf Avg. 1,966 $7.78M Percentage Increase/ Decrease- PNP vs. OHMS 64% 0.1% 24-hr IP (BOEPD) $ (Millions) Production Uncemented Cemented Plug & Sliding Sleeve Avg. Perf Avg. Cost Uncemented Sliding Sleeve Avg. Cemented Plug & Perf Avg.

16 Comparison- Later Results Wells Completed in 2013-Operator #2 5 Historical Industry Practice Current Industry Practice Planned Company Practice Lateral 2,000-5,000 ft. 6,000+ ft. Longer than 7,200+ ft. Lateral Placement Varied, trial and error Well defined Well defined Frac Type Slick water Hybrid Hybrid * Proppant Less than 1,400 lb/ft 1,400 lb/ft + 1,400 lb/ft + Cluster Spacing 70-ft or greater 66-ft or less 50-ft New Style: Cemented Liner Completion using Plug and Perf Results: Avg IP BOEPD 3 Wells 38% over OHMS 3,060 4 Wells 77% over OHMS 2,094 2 Wells 91% over OHMS 462 M Ultimate recovery * Hybrid Frac: Slick water pad Gel during prop FracDesign: Using Ceramic Proppant Increased Proppant per Lateral Ft. Increased Stage Density Employing Simultaneous or Zipper Fracs(Two adjacent wells frac d at same time)

17 Summary CHPP Steps: 1. Clean-out Run> first run after running casing and cementing (becoming optional) Alternate: Combination CT Clean-out with Abrasive Jet Perforating (non-explosive) 2. TCP Toe Prep> required as no perforations yet (can t pump into formation) Two primary methods- 1) Tubing conveyed on Workover Rig or 2) Coiled Tubing conveyed Alternate: Casing Toe Gun, run on casing but requires larger bore hole and high-temp explosives Alternate: Casing Toe Sleeve, run on casing but requires over-displacement of cement (becoming method of choice for toe prep) 3. Bullhead Frac down casing 4. WirelinePump-down Plug and Perf> unlimited stages but risky (method of choice after flow into formation established) Alternate: TCP Plug and Perf(annular pressure) Alternate: TCP Plug and Perf(tubing pressure) Each stage followed by Bullhead Frac down casing 5. Mill up Composite Plugs Fracflow back, Clean up, and put well on Production

18 Summary OHMS vs. CHPP: OpenholeMultistage systems delivered good results early in Shale Development, Primarily because of equipment shortages, high rates for services and standby costs. Saves costs as multiple stages can be frac dcontinuously Saves time as no perforating or plug runs are required and no plugs to drill up But, completion and frac port locations must be planned well in advance But, cost of equipment remains high (machining costs have not reduced proportionally) Still viable system but production rates reversing toward CHPP.

19 Summary OHMS vs. CHPP: Cased Hole Plug-N-Perf system is showing improving results due to new techniques Not stand-alone, one aspect of new completion technique which includes changes in frac. Costs have come down significantly for coiled tubing and frac standby, now similar in cost More points of contact with formation aid in formation breakdown and proppant placement. More flexible, can add stages quickly and easily and optimize the fracin real time Takes longer, but sometimes investment is worthwhile to get higher productivity Overall costs are similar but production rates are improving. Good news for the Perforating Industry-We re Still in the Game! Thank you! Questions?

20 References 1. Cheselin, R., QuittitutConsulting (2011, August). OpenholeMultistage vs. Plug-N-PerfCompletions: Sleeves vs. Shots-The Debase Continues. 2. Rivenbark, M., & Appleton, J. (2013, January 28). Cemented Versus Open Hole Completions: What is Best for Your Well? Society of Petroleum Engineers. doi: / ms 3. Whiting.com (2014, April). Current Corporate Presentation 4. Bakken.com (2013, December 26). Whiting Petroleum Exploits Cemented Liners For Major Production Gains 5. HalconResources. Com (2013, June 10). HalcónResources Provides Operational Update: Company Reports 3,060 Boe/d IP Rate on Latest Fort Berthold Area BakkenWell