After a well has produced its last oil and gas, it must be plugged and abandoned (P&A). The phrase suggests it will remain sealed forever. “What we want when we abandon a well is we never want to come back to it,” said Don Stelling, president of Chevron Environmental Management Company. Compared with the 30- to 40-year life expected of most facilities, “it is a difficult engineering standard.”
And it will be getting more difficult. The wells of the future include many in stormy seas and deep water, magnifying the cost of what the United States Bureau of Safety and Environmental Enforcement (BSEE) describes on its website as “safely plugging the hole in the Earth’s crust.”
Estimating the scale of this work is a highly inexact exercise. There are many interdependent variables affecting cost and demand.
Based on the wells that will someday need to be decommissioned, the value of the market could exceed USD 250 billion using current methods, said Martial Burguieres, vice president of marine well services for Wild Well Control, which does plugging and abandonment work. Actual demand will depend on what operators can afford and regulators require.
One sure thing is that the number of wells needing to be permanently plugged will continue to rise.
“As long as they are drilling new wells. The backlog of wells to be plugged and abandoned is humongous,” said Bart Joppe, global business development manager for plug and abandonment at Baker Hughes.
A key variable in the volume of work done is the cost per well. P&A work is the most expensive component when shutting down an offshore field. Reducing that expense is critical in places where oil companies are experiencing decommissioning price shock, such as the North Sea or offshore California, and in the deep waters of the US Gulf of Mexico.
“P&A is a massive problem. There are huge cost overruns,” said Brian Twomey, managing director of Reverse Engineering Services, which offers decommissioning advice and classes.
Operators are also having to adapt to changing rules over the past 5 years in Norway, the United Kingdom and the US. “Regulation is becoming more stringent and the volume of work is going up,” Joppe said. “We have seen customers screaming over large increases in costs and in the volume of work. We have definitely gotten more requests for new technology.”
At the top of the technology wish list are ways to work on wells without paying for a drilling rig and riser, and tools capable of dependably doing jobs faster because even the “lighter” intervention vessels command hefty day rates. There is also more attention paid to the materials used to create lasting barriers to ensure wells never leak, because the cost of going back to fix a leaking deepwater well is punishingly high. (See sidebar on well cementing.)
Without new methods to reduce the cost, the expense of plugging and abandoning difficult wells offers a strong argument for postponing the work.
“A lot of operators will not admit it, but there is nothing in the budget to provide money for these wells” at current prices, which are both high and hard to predict, Burguieres said. “Drilling rigs should be drilling. We can handle this.”
That assertion will be tested in the Gulf of Mexico, which is a proving ground for new deepwater removal approaches. The BSEE’s “idle iron” rule sets a deadline requiring that inactive wells be plugged and production equipment be removed.
Johnson, Michael (Rick) (Halliburton Energy Services Group) | Ardoin, Kevin Wendell (Halliburton) | Sweep, Miles Norman (Chevron ETC) | Wyatt, Nathan Barrett (Halliburton Energy Services Grp) | Benet, Paul (Chevron)
This document reviews challenges and solution to previously overwhelming issues regarding 14-in. liner placement in the Gulf of Mexico. Necessity and considerable effort are required to deal with multiple mobile/active tar zones, associated with fault zones throughout the sediment sections and below the base of salt. Deploying liners to the desired depth through such hole sections have resulted in costly non-productive time (NPT). The large bore expandable liner hanger drilling/washing capabilities provides a reliable method to assist the operator in reaching their targets.
Advancements in casing connection technology have provided enhanced torque capabilities for some time. Today, the large-bore expandable liner hanger (LBELH) system provides the capability and reliability to deliver torque to the liner shoe. This added rotation and reciprocation capability while circulating is at the heart of NPT reduction.
The running tools to deliver such a system have the capacity to provide 110K foot pounds of torque at top of liner (TOL). Reaming/drilling attachments to the liner shoe have advanced to a point that allows operators to take advantage of the technique to deliver the liner to its target depth.
This combination of equipment allowed a major Gulf of Mexico operator to wash and ream a 14-in. liner through tar and shale, inside their 16-½-in. borehole. Two successful attempts totaling 7-½ hours of reaming resulted in gains of 335 feet. The final effort was to wash and ream the liner down inside the 14-½-in. pilot hole. This was an additional 30 feet of "drilling conditions?? to total depth (TD), requiring an additional 45 minutes of torque and vibration.
The liner was cemented and the hanger was set and tested. The operator commented: "Excellent results??, [and that he was]??Very pleased to get this critical and difficult section cased off??. (Benet, 2012)
A purpose-built finite-element model (FEM) is applied to simulate radial displacement of a casing string constrained within an outer wellbore. The FEM represents a fully stiff-string model wherein the casing is approximated by general beam elements with 6 degrees of freedom at each node to account for all possible physical displacements and rotations. Results predicted include deflection of the casing centerline from the wellbore centerline, effective dogleg curvature, bending deformation, wall contact forces, and bending stress magnification.
In critical well casing design, accurate assumptions regarding bending stiffness may be necessary to avoid overly-conservative as well as non-conservative analysis. Challenging HPHT and extreme temperature wells are opportunities where increased design efficiency can be crucial. Alternatively, design for extreme loads such as overpull loads in long deviated wells may be non-conservative if severe bending stresses are not considered.
A realistic case study is presented which demonstrates the possibility to achieve cost efficiency by means of optimized casing design. Also a case study is presented where a non-conservative design may result if severe bending loads are not modeled. The purpose-built FEM code is in many ways preferable to use of commercial FEA packages because of the time-consuming effort required to build up the detailed model.
In typical casing and tubular stress design, a "soft-string" model assumes casing strings are coincident with the wellbore centerline. The known or assumed wellbore curvature is applied directly to the casing string. Any effect of casing string stiffness and allowable radial displacement within the outer wellbore is ignored. In many cases this results in an overly-conservative analysis. Likewise the impact of bending stress magnification is typically ignored along with the effects of centralizer placement. This may also be non-conservative for critical overpull situations such as in ERD and horizontal wells.
What are reasons to apply a finite-element model (FEM) to the task of casing design? The need may arise in various aspects of advanced casing design when the stiffness of the casing tubular has a significant impact on design loads. To appreciate this, it is helpful to review the place of casing design in the context of the general tubular design problem. Torque and drag (T&D) analysis focuses on the parameters enabling and/or preventing the particular operation of running the tubular string into the well and if necessary pulling out. This is often a critical function in the design of drilling and workover operations and sometimes may be a critical issue for casing and completions. In contrast, casing and completion design is usually more focused on the changing loads over the life of the well after the string is landed and fixed in place.
Some physical parameters are always incorporated into the load calculations for all phases of tubular design. These include pipe self-weight due to gravity, buoyancy and the local angle of deviation. Pressure conditions result in burst and collapse loads and may induce resultant axial loads as well. Likewise downhole temperatures affect pipe material resistance and may induce axial loads depending on boundary conditions. Buckling results in additional pipe stress and may also have a direct impact on the ability to run pipe.
An outer casing leak can be a significant well integrity issue, primarily due to the inability to easily access the leak site for intervention. Recent outer casing failures caused by external corrosion on some wells in the Kuparuk Field of Alaska prompted research for a non-invasive repair method to delay or negate the need for a rig workover. Limited options for downhole access on outer concentric casing strings have an impact on the ability to define the leak in terms of location, size and shape, and consequently the ability to effect a seal of the casing.
The Platelet® technology discussed in this paper is an innovative means of sealing leaks which involves the remote injection of discrete particles into a well which are then carried to the leak site in the fluid flow. When the platelets reach the vicinity of the leak, fluid forces entrain them into the leak and hold them against the casing wall thus facilitating a seal allowing the well to be returned to service.
Previously proven for applications in subsea pipelines, platelet technology over the last 12 months has successfully been developed for downhole use. In January 2009, specifically engineered platelets were deployed into well annuli for the first time.
Two case studies will be presented where the technology has been used in the Kuparuk field in Alaska. In the first instance a ¼?? corrosion induced hole in the surface casing at a depth of 126 ft was sealed with a single platelet by a deployment from surface into the outer annulus. The well was initially leaking at a rate of 0.5 bpm and subsequently passed an 1800 psi mechanical integrity test. The second study will review a seal of a 0.26 bpm leak at 30 ft depth which eventually gave out.
The paper will review the front end engineering development, the well site deployment, and lessons learned. The paper concludes by demonstrating the successful use of the platelet technology for sealing annulus leaks and how the technology has successfully postponed or negated the need for a rig workover to repair a surface casing leak. The results from this study have provided valuable insight into the behavior of the platelets in the fluid flow before entrainment and the behavior in the leak after entrainment.
Casing connections in thermal wells, such as SAGD and CSS wells, experience extreme loads due to exposure to high temperatures up to 200ºC-350ºC, stresses exceeding the elastic limit, and cyclic plastic deformation. To-date, no standard procedure has been adopted by the industry to qualify casing connections for such conditions. In particular, the existing evaluation standard ISO13679/API5C5 exclude temperatures above 180ºC and tubular loads beyond pipe body yield. Proprietary procedures have been used to qualify connections for individual thermal operations, but none of those has been accepted as an industry standard.
This paper introduces a new protocol for evaluating casing connections for thermal well applications: Thermal Well Casing Connection Evaluation Protocol (TWCCEP) founded on long-standing work in the thermal-well arena. TWCCEPT has been developed through a multi-client project, sponsored by operators and connection manufacturers involved in thermal-well operations in Canada: EnCana, Husky Energy, Evraz (formerly Ipsco), Nexen, Pengrowth, Petro-Canada, Shell, TenarisHydril, and Total. Recently, International Organization for Standardization (ISO) Technical Committee 67 Sub Committee 5 registered a new work item to consider adopted TWCCEP as an international standard.
This paper refers to the TWCCEPT version available at the time of submitting the paper manuscript. TWCCEP employs both analytical and experimental procedures to assess performance of a candidate connection under conditions typical of service in thermally-stimulated wells. The objective of the analytical component is to assess sensitivities of the candidate connection to selected design variables, and identify worst-case combinations of those variables for subsequent configuration of specimens for physical testing. The purpose of the physical testing is to verify performance of the connection specimens under assembly-and-loading conditions simulating the thermal-well service.
In addition to the protocol overview, this paper illustrates how engineering analysis, numerical simulation, and reduced-scale physical testing were used in the protocol development to examine impacts of various design and loading variables on connection strength and sealability, and how those results were utilized to formulate the analysis-and-test matrix prescribed in the TWCCEP evaluation procedure.
Adoption and consistent use of TWCCEP is expected to increase operational reliability and decrease failure potential of casing strings in thermal wells. Learnings from the protocol development will also help define requirements for connection re-qualification in cases when one or more of the design variables change (i.e., in product line qualification).
Thermal well service conditions
Loading conditions in extreme-temperature wells, such as Steam Assisted Gravity Drainage (SAGD) and Cyclic Stream Stimulation (CSS), are severe. Maximum operating temperatures in those wells currently reach into the interval between 200ºC and 350ºC. Large temperature variations occur due to production techniques and well interventions, leading to cyclic heating and cooling. When a restrained tubular, such as a cemented casing string, is subject to a large temperature increases during heating, constrained thermal expansion generates mechanical forces in the pipe. Those strain-induced forces are of sufficient magnitude to yield the pipe, even if it is made of a high-grade material. Theoretically, a high-yield pipe material could be chosen to avoid yielding, but typically such choices are not practical due to reduced resistance to environmental cracking and high cost. In consequence, average stresses in the pipe-connection system exceed the full-pipe-body yield stress, and the system deforms plastically. In addition, strain localization in weaker sections of the pipe-connection system can lead to local plastic strains higher than the average strain, which compounds the degree of the local plastic deformation.
Anders, Joseph L. (BP Exploration Alaska Inc.) | Cismoski, Douglas A. (BP Alaska Exploration Inc.) | Daniel, Ryan John (BP Alaska Drilling and Wells) | Dube, Anna Therese (BP Exploration Alaska Inc.) | Engel, Harold Robert (BP Alaska Exploration Inc.) | Hughes, Andrea Lea (Halliburton Energy Services Group) | Norene, T. (BP Exploration) | Hamilton, R. (FMC) | Mohr, W. (Edison Welding Institute)
While pre-heating the surface casing landing mandrel in preparation of welding to repair a leak on Prudhoe Bay well P2-15, the wellhead suddenly and unexpectedly moved downward approximately 18 inches. This failure resulted in an injury and required a rig workover to repair the well.
The wellhead was cut below the surface casing landing mandrel and sent to a company specializing in metallurgical analysis to determine the cause of movement. A section of the surface casing was identified with reduced wall thickness due to drilling wear. As heat was applied to raise the wellhead to welding temperature, the reduced wall thickness section of the surface casing experienced a temperature increase greater than the design pre-heat temperature. This thin-walled section of the casing began losing tensile strength, eventually resulting in the surface casing collapsing inward and allowing the wellhead to rapidly subside.
This paper discusses the causes of the failure and presents recommendations to prevent future failures of this type.
Discussion of Incident
Prudhoe Bay well P2-15 is in WAG (wateralternating- gas) injection service. It was drilled in 1994 and completed using 10-3/4 inch surface casing and 20 inch conductor casing. In 2004, leakage from the lower connection of the surface casing landing mandrel was identified. The well remained in injection service until September 2006, then was shut-in pending repair of the leak.
As well integrity is of utmost importance for personnel safety and environmental interests there is an ever increasing need for tools and systems that verify and confirm the status of wells with suspect integrity. Recent near-surface, outer casing failures caused by external corrosion on relatively new wells in the Kuparuk Field of Alaska prompted research for a non-invasive predictive method to foresee failure and aid repair prioritization. There are a variety of tools and methods available to locate leak points and corrosion inside of tubulars, but very little literature exists concerning external corrosion and damage detection on outer and middle concentric strings of casing. The following method is a valuable qualitative approach used to determine existence and severity of shallow external surface casing corrosion before leaks occur.
The technique uses a logging tool that analyzes the variations of metal thickness within three concentric sets of down-hole tubulars and identifies areas where metal loss exists. The metal loss combined with assumed or known internal tubing condition reveals the wells with the highest risk for shallow surface casing leaks. When a high risk area is discovered proactive excavation repair plans can be made before any safety or environmental problems occur. This paper summarizes the tool, technical approach and assumptions, limiting factors, and the remarkable comparison between the metal thickness logs and the actual external surface casing corrosion observed on 12 wells after excavating each up to 27 ft in the Greater Kuparuk Area. Future plans and strategy using the technique are also discussed in the paper.
High explosives, particularly nitroglycerin, have been used in torpedoes forthe purpose of shooting oil and gas wells for more than 60 years. The earlyhistory of the oil industry in Pennsylvania is not clear as to who actuallytorpedoed the first well, although in 1865 the Roberts Torpedo Co. procured apatent covering the process. Gunpowder was first used, although nitroglycerinwas substituted shortly afterwards.
Wells are shot for the purpose of increasing the flow of oil and gas. Ashot-hole in the producing horizon, with its contributory fissures andfractures, increases the area of and stimulates drainage into the hole. Theshot-hole also acts as a collecting basin from which the oil is pumped. As arule, hard or close-grained sands or limes are shot, other more or less porousand soft formations usually do not require shooting, and might be injured byblasting. Shooting is also resorted to in mechanical trouble such asstraightening crooked holes, sidetracking pipe or tools, and for severingfrozen strings of casing or drill pipe. Explosives are also used sometimes toextinguish oil or gas-well fires although that work, which involves unusualconditions and methods, does not properly come within the classification ofoil-well shooting.
Some Factors To Be Considered In Shooting Wells
Although nitroglycerin has been used extensively for more than half a centuryin shooting oil and gas wells, there is still a great deal of uncertainty as tothe proper method of shooting or the amount of explosive required to producebest results in a particular formation. The possibility of shootingunproductive or cavey formations above or below the productive horizons,shooting into lower water, destroying casing seats, and the splitting orcollapsing of casing strings, are factors that require consideration.