Reliability of Annular Pressure Buildup (APB) Mitigation Technologies 12121-6502-01 Bob Pilko Blade Energy Partners, Ltd. Best of RPSEA 10 Years of Research - Ultra-Deepwater and Onshore Technology Conference August 30-31, 2016 The San Luis Resort, Spa & Conference Center, Galveston, TX 1 rpsea.org
Acknowledgements 2 Ken Armagost, Anadarko for championing the project Project funding: o Bill Head & James Pappas, RPSEA PM o Sheldon Funk, Contractual Representative, Department of Energy o Robert Vagnetti, Technical Representative, Department of Energy Working peer group (WPG) o Mike Payne, BP, o David Pattillo, Anadarko, o Robert Mitchell, Independent consultant. o Jim Powers, Chevron o Antonio Lage, Petrobras Blade Energy Partners - Management & project team o Bob Pilko, Project leader o Udaya B. Sathuvalli, Chief Scientist & Researcher o Alexa Gonzalez o P. V. (Suri) Suryanarayana (Blade in-house Technical Advisor) o Cathy Clough (Admin. & Finance) o Parveen Sachdeva External research partner o Yildiz Bayazitoglu (Research partner, Rice University)
Project overview and scope of work o Project goals- Survey APB mitigation techniques Tested & tried, conceptual, awaiting field trial or pending patent Determine engineering bases & identify performance metrics Use the performance metrics to compare efficacy of mitigation techniques Assess Ability for field implementation Robust-ness in the face of uncertainties that may emerge over the course of well life Reliability of technique during life of well Case studies, as and when available, and provide a decision tool for a drilling/design engineer Disseminate results to the industry 3
In this presentation.. o o Reliability of current mitigation techniques Results of industry survey APB measurements and field studies Basis of design Currently used mitigation devices Mitigation technique selection (screening procedure) Brief survey of potential future mitigation techniques Focus on new, developing, and prototyped methods Insulated tubing Controlled placement of gas cap Shrinking fluids Fluids with hollow glass spheres Elastic hollow polypropylene spheres Access to annuli Trapped pressure compensator Gas laden fluids Sag resistant muds Compressible carbon 4
Reliability of a system (wellbore) contd. 5 o o o Reliability of a mitigation device Assess from frequency data (a posteriori) Exhaustive enumeration of sample space & counting favorable outcomes (classical a priori) Quantitative physical model of the device or process + engineering parameter (usually performed at the design stage) Four stages to assess reliability of a given mitigation technique Reliability of the component(s) that make up the mitigation strategy Eg. Gas cap dependence on the cementing, uncertainty in formation back up on rupture disk, etc. Multiple failure modes Eg. Failure of vacuum in a VIT joint, degradation of insulating properties of fluid, Effect of unreliability of the mitigation device on structural response of neighboring components (i.e. effect on system) Eg. Rupture disk communication with cement channel, interaction with secondary/tertiary devices Impact on expected life of well and need for intervention/repair due to inadequate reliability Difficult (or impossible) to quantify all aspects Numerical values from simulations may not reflect actual system reliability Qualitative notions (high, medium and low) may have to be invoked o Assessment parameters Ability for field implementation (installation) Robust-ness in the face of uncertainties that may emerge over the course of well life, Reliability of technique during life of well
Selected results of operator survey Analysis of the ten (10) responses received. 6
APB mitigation techniques o APB is the response of a fluid in an elastic container to pressure and temperature changes Temperature change, DT Fluid volume change, DV Pressure change, DP o Two types of mitigation techniques Type I methods reduce lateral heat transfer from the tubing Lower DT in the annuli Lower DV and therefore lower DP Type II methods increase the flexibility of the annulus Alters DP/DT of the annulus Typical deepwater wellbore unmitigated annulus flexibility 80 to 150 psi/ F 7 Tested and tried methods
Tested and tried mitigation methods 8 o Leak off to formation at previous casing shoe Some designers do not consider an open shoe adequate mitigation o Rupture disks Bi-directional (burst and collapse) Intermediate and outer strings o Solid syntactic foam Crush and relieve pressure at pre-determined pressure o Gas Caps (Nitrified spacer) o VIT Increases the compressibility of the fluid Mitigation by reducing heat transfer o Strength of tubular materials Advanced strength and load considerations VIT
9 Pompano (SPE 89775)
Field measurements of annular conditions o o o Annular conditions are inferred in outer annuli Pressure Temperature Density Case studies Marlin incident and redesign (SPE 74528, 74529 and 74530) Pompano incident (89775) Mad Dog incident (109882) Field measurements SPE 22102: Evaluation of VIT for Paraffin control at Norman wells (Esso Canada) SPE 26738: Field trial results of annular pressure behavior in a HPHT well (Shell) SPE 88735: Transient Behavior of Annular Pressure Build-up in HP/HT Wells (Shell) OTC 19286: Real-Time casing annulus pressure monitoring in a subsea HPHT exploration well (Total) SPE 163476: Modeling reveals hidden conditions that can impair wellbore stability and integrity (Encana) 10
Well design for APB a reprise o o o APB loads are production induced loads Operational loads (as opposed to a survival load); Prob. of occurrence ~ 1 (nearly certain) Frequency.? They affect the outer drilling strings Design goals Higher OD/WT ratios lower pressure capacities Shallower annuli Higher fluid DT, Higher APB Flow stream (tubing & production casing) integrity Prevent untoward wellbore breach (underground blowouts, mudline leaks etc.) Design basis Each annulus to stand on its own (SPE # 74528, 74529, & 74530) Outer string burst Inner string collapse Allowable APB in an annulus Tubular design basis 11 If Expected APB > Allowable APB then Re-design well Mitigate APB Do both
Wellbore temperatures APB ~ 80 to 150 psi per F of DT avg 12
Reliability of a system (wellbore) Primitive Design Variables (Size, grade, crush pressure etc.) Design Requirements (DFs, TRLs, materials allowable wear ) Thermal Loading Mechanical Design / Analysis (Axial, burst, collapse, ) Component Reliability (e.g. burst disk, etc.) System (wellbore) Model System Reliability Assessment 13
Collapse safety factors and reliability Results based on first order perturbation of API TR 5C3 collapse design equations Statistics from Appendix F 14
PVT response of annuli TYPE I TYPE II 15
Vacuum Insulated Tubing (VIT) o o o o o VIT consists of two tubes, welded together at the ends of the shorter tube Shorter tube does not contain connection threads Isolated annulus to which a vacuum is applied (20 millitor ~ 4 10-4 psi) The annulus contains: Alternating layers of aluminum foil and scrim Aluminum foil; radiant barrier perforated to cut bake times Scrim; conductive barrier between the layers of aluminum foil Getter installed inside inner most wrap Absorbs molecular gases, primarily hydrogen, inside the vacuum chamber in order to preserve the vacuum over the long term Annulus A can be monitored 16
Reliability of VIT o Thermal design 17 Allowable APB Length of insulated tube Coupling insulation Diffusion in Annulus A Heat loss at connection Heat loss at VIT to conventional tubing interface o Mechanical design Tubing mechanics o Weld integrity Tubing movement and stresses Load response of inner and outer pipes of individual VIT joints Heat treatment Sour service Fatigue Connection insulation Fillet weld cross section
18 Thermal response of annuli
Measured Depth, ft. Measured Depth, ft. Vertical diffusion in an annulus Marlin Well 0 Temperature, Deg F 0 50 100 150 200 Temperature, Deg F 80 90 100 110 120 130 5100 1000 2000 3000 4000 5000 6000 7000 P&T Gauge P&T Gauge POTH P&T Gauge SSSV 5150 5200 5250 5300 5350 5400 5450 5500 5550 Body ~40 ft. Connections 8000 5600 All figures are excerpted from SPE 74530 19
Type II mitigation techniques o Type II mitigation techniques change the PVT response of the annulus, Vann, m ini, m ini, m ini, m D m Pfin, m z Tfin, m z DVfl m dvann, m z P z, T 20
21 Rupture disks
22 Basis of design
23 Syntactic foams
Physical behavior of syntactic foam Variation of crush pressure with temperature 24
25 Reliability of syntactic foams
Nitrogen gas caps o Introduce compressible phase into trapped fluid to provide relief o Acts as a mechanical Shock absorber o Limitations are: Ability to introduce gas Migration pressure of gas from point of introduction to surface (hydrostatic at placement depth of the mud can reach surface) o High ECD due to higher viscosity o Operators have mostly stopped using gas caps for APB mitigation in the recent five years 26
Controlled placement of N 2 gas cap Seal Assembly Work String Upper Valve Seal Assembly Work String Upper Valve Mud in Annulus Nitrogen Gas in Annulus Valve Actuator Valve Actuator Outer Casing Lower Valve Lower Valve Mud Remaining in Annulus TOC TOC Ref: US Patent #PCT/US13/54075 Filed 27 2 valves are fitted on the inner casing of the annulus where gas cap is planned. Valves are fitted with valve actuator assembly. Work string is lowered and attached to upper valve. Both valves are opened. Gas is injected from upper valve, which pushes the annulus fluid in the inner annulus through the lower valve, thereby creating a gas cap in outer annulus.
Open holes o Open hole sections Shales (non-zero permeability) Salts Zero or no-permeability, leak off ( due to fracture) at pressures > OBG o Causes of pore closure Static sag Particle settling Consolidation of a settled sediment Shallow plugs that isolate annulus Other mechanisms 28
29 Static sag
Salt zones A typical leak off test Viscoelastic response 30
Depth (m) Interaction between mitigation devices 1300 1400 Pressure (bar) 200 225 250 275 300 325 350 375 400 425 450 475 500 Foam Parameters: Crush presure at 40ºC: 308 bar Crush presure at 80ºC: 274 bar 1" Thick Foam Modules Internal Pressure Crush Pressure Pressure Outside BD (Condition 1) Pressure Outside BD (Condition 2) Pressure Outside BD (Condition 3) 1500 1600 Condition 1: Pore Pressurer Backup Outside 20"; No Packer Leak; Activation at Rated Disk Rupture Condition 2: Sea-Water Backup Outside 20"; No Packer Leak; Activation at 95% of Rated Disk Rupture Condition 3: Pore Pressure Backup Outside 20"; Packer Leak below 14" TOC; Activation at 105% of Rated Disk Rupture 1700 1800 Burst Disk Activation Range 1900 Custom Burst Disk Parameters: Rated Activation pressure: 227 bar Back Pressure: 207 bar Activation Temperature: 110ºC Ensures Min 14" Collapse SF =1.03 31 2000 Foam Activation Range
32 Comparison of existing mitigation techniques
System (wellbore) integrity 33 Both approaches to probability must be used
34 Mitigation technique screening
35 Mitigation technique screening contd.
36 Mitigation technique screening contd.
37 Mitigation technique screening contd.
Emerging techniques o Annulus A Special rheology (k,, C p, m, t) Solid insulation o Outer annuli Syntactic foam, Izo-flex insulation TM 1 1 P T T Gas laden fluids,, - alter density and density variation with P & T Polymeric fluids that shrink with temperature increase. After activation, contraction counters the thermal expansion Fluids with hollow glass spheres (HGS) Engineered so that a substantial fraction of them crush at a predetermined pressure when introduced in a fluid filled annulus that is trapped. Issues in downhole placement Downhole pressure compensators Access to wellhead or outermost annuli via ROV drilling P 38
Update - Izoflex TM insulated tubing o Pipe-in-pipe insulation system Concentric pipes with evacuated (~ 10 torr) annulus Gap between pipes is filled with Izoflex TM insulation Thermal conductivity in vacuum is a third of its value at atmospheric pressure Insulation cannot come in contact with fluid Bayonet system insulates connection Connection leak will not affect the insulation Vacuum integrity ~ 30 years o Developed for the nuclear industry in 1950s Used in offshore flowlines in 1970s Insulated tubing in 2006 39
Insulating packer fluids 40 o Fluids with engineered rheology Designed to minimize lateral heat flow by altering convective flow Gel strength (yield point) adjusted to delay onset of convection or minimize convection Densities from 8.5 to 15.0 lb/gal Thermal conductivities (k) of 0.123 to 0.177 BTU/hr-ft- F Claimed to be thermally stable up to 600 F Trademarked products Safetherm TM from MI-Swaco N-Solate TM from Halliburton Insulgel TM (an early predecessor, may no longer be available) o Minimum requirements from APB control standpoint Suitable viscosity and yield point Low thermal conductivity Rheological stability viscosity & YP do not degrade with time thermal conductivity remain stable
NSOLATE TM Test results Non-functional IPF Functional IPF 41 Convection dominates- Erases radial temperature gradient Information provided by Halliburton - Ryan Riker Conduction dominates- Low conductivity creates temperature gradient
Fluids with hollow glass microspheres o o Placed in an annulus by pumping them ahead of the cementing fluid train. When the beads break at a target pressure (or a range of target pressures), the resulting void space is occupied by the expanding fluid and relieved APB in the annulus. BHCP may exceed the collapse pressure of the glass spheres, destroying the utility of the fluid. Due to their small diameter, oilfield shale shakers cannot always be used to remove the spheres from the mud when they return to the surface. 3M Hollow Glass Microspheres S 38 Laboratory tests showed, microspheres were not damaged by conventional mud pumps or rig mud handling equipment. Laboratory tests, showed that with proper nozzle selection and standoff, sphere breakage can be minimized. New Lightweight Fluids for Underbalanced Drilling. U.S. Department of Energy s Federal Energy Technology Center. Contract DE-AC21-94MC31197 42
Elastic hollow polypropylene spheres o Placed within the annulus, hollow particles that buckle at or near a defined pressure. The elastic hollow particles are designed such that they buckle in a sufficiently elastic manner to allow them to rebound towards their original shape as the pressure decreases. Potential Problems and Reliability Sheperd, J.E., Rakow, J.F., Pattillo, P.D. (2010, May 6). Patent US 2010/0113310 A1- Elastic Hollow Particles for Annular Pressure Buildup Mitigation. Composition is still proprietary. Further studies need to be made in order to be able to prove reliability or results of their application. 43
Settling (sag) resistant muds o Sag is the occurrence of density variations in drilling mud while circulating o Two types of sag Static sag: occurs when fluid is shut-in for an extended period of time Dynamic sag: occurs in inclined holes, and settling is enhanced by convective currents driven by density differences in fluid across annulus (Boycott effect) o Sag is followed by slumping- cuttings bed reaches a critical thickness cuttings slide down 44
Settling times for barites Stokesian settling times ~ few months or less for a 3000 ft annulus Smaller particles, Brownian regime Larger particles, Hydrodynamic regime SG of barite = 4.3 Viscosity (m) of water = 1 cp 45
46 Relative merits of emerging Type II technologies
Access to annuli ROV drill the outer string 47 o Drill a vent hole in the outer string to access and regulate pressure in the B annulus by using Remote Operated Vehicle (ROV). o Oceaneering developed, tested, and utilized a similar technology initially for Terra Nova Development for Petro-Canada o A modification of those tools was later used at Chevron s Agbami Project in Deepwater Nigeria adopted this technology for their deepwater development wells. http://www.oceaneering.com/rovs/rov-systems/millennium-plus-rov/ For the Tahiti wells, this technique was selected to mitigate trapped pressure. The procedure included drilling a vent hole through the 36 and into the 23 x 2 wellhead adapter on the 22 surface casing utilizing Oceaneering s Annulus Drilling Tool (ADT). A plug with seals was inserted into the hole and connected to a flying lead that was routed back to an ROV control panel. On this panel a gauge to monitor pressure, redundant block valves and pressure relief valve that allows annulus to vent once the well is placed on production. The panel is connected to the tree via electric flying lead which allows for continuous monitoring of the annulus B. The installation of this equipment was performed following the 10-3/4in. tieback installations when the wellbore was completely isolated from the vent hole. In addition, burst disks were placed in the 22in. string bellow the 16in. hanger/seal in order to vent the trapped 16in. x 22in. annulus ( C annulus). This annulus was inaccessible from the proposed drilled holes in the 22in. surface casing. The technology was successfully deployed and tested on three wells. Rivas, F.L., Sanclemente, J.F., Ricketts, K. 2009. Tahiti Subsurface Drilling and Completion Technology Challenges and Accomplishments. Paper OTC 19861 prepare for the Offshore Technology Conference, Houston, Texas, 4-7 May.
Trapped pressure compensator (TPC) o o Consists of a sealed, nitrogen-filled chamber installed in the tubing string and inserted inside the casing of a well to prevent pressure created by trapped annular completion fluid from rupturing or collapsing the casing. It appears that the principle is, similar to that of a nitrogen gas cap. However, the gas cap is introduced into the annulus via the compensator Eemskanaal-2 (EKL-2) well in Groningen field, Holland, by Shell Oil Company. Drilled more than 30 years ago and had a 10-3/4in, 40.5lb casing as the intermediate casing. Halliburton replaced the completion equipment by stabbing a tailpipe assembly onto a 7-5/8-in. liner top at 3,773-ft (1,151-m) depths and then setting a packer above in 10-3/4 in. casing. This created a 328-ft trapped column of annular fluid. The compensator consisted of 2 concentric pipes, 7-5/8in. and 9-5/8in, with a pressure activated shear disk on the external 9-5/8in casing. Contained 3 expansion chambers with shear values selected to rupture in stages, two of them designated to return the max. expected pressure, and the third one as a redundant piece. Well worked over, testing confirmed productivity of EKL-2 increased by 60% to 63.5mln scf/d. 48 Siemers, G., Ukomah, T., Mack, R., Noel, G. 2003. Development and Field Testing of Solid Expandable Corrosion Resistant Cased-Hole Liners to Boost Gas Production in Corrosive Environments. Paper OTC 15149 presented at Offshore Technology Conference, Houston, Texas, 5-8 May
49 Questions?
Contacts Principal Investigator: Bob Pilko Blade Energy Partners, Ltd. bpilko@blade-energy.com 281-206-2000 Project Manager: Rob Vagnetti NETL robert.vagnetti@netl.doe.gov 304-285-1334 50 Technical Coordinator: Bill Head RPSEA bhead@rpsea.org 281-313-9555