Blowout Control Technical Reference 1
Abstracts
Blowout Control Technical Reference Part 01-Strategy and Planning Emergency management tools such as prior remedial contingency planning and a designated task force help those responsible for emergencies perform critical tasks confidently, effectively and efficiently.
Part 02-Logistics Special services are often unfamiliar to operators and may not be available locally. Critical support and transportation are best managed by pre-planning to identify service, material and equipment needs. Vendors can be pre-qualified and contracts are signed in advance
Part 03-Insurance For the assured to be prepared for the emergency and be adequately covered, correct policy wording on Control-of-well coverage under OEE or EED 8/86 forms needs to be worked out in advance
Part 04-Documented Contingency Plans The first step to reduce vulnerability posed by a potential blowout is a documented emergency management and response system that will advise you of initiatives that must be addressed
Part 05-Hydraulics Modeling Matching known downhole well information with surface flow characteristics of a blowout via computer allows selection of the most efficient kill method
Part 06-Underground Blowouts Underground blowouts between subsurface intervals are common and can result in a significant escalation threat if not recognized quickly and controlled correctly
Part 07-Shallow Gas Blowouts After underground blowouts, shallow gas blowouts are the second most common type of blowout and the most common type of surface blowout. Loss of rig, platform and life have resulted from shallow gas blowouts. Invariably, the well is lost
Part 08-HPHT Case History Control of an offshore HPHT underground blowout. Lessons were learned as to limitations of dynamic kills and novel use of gunk squeezes with a 1 1/4-in. snubbing string to accomplish control
Part 09-Firefighting The mechanics of oil/gas fires, meltdown and secondary damage, water/chemical/explosive extinguishing methods and considerations for voluntary ignition
Part 10-Surface Intervention Methods Descriptions of debris removal techniques; special services like junk shots, hot tapping and freezing; and proven methods of well capping
Part 11-Relief Wells Advancements in technology and application engineering make the relief well a more practical blowout control option.
Part 12-Well Control Incident Management How developing these two disciplines allows an operator to more efficiently manage a blowout
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Blowout Control Technical Reference
Part 1 Strategy and planning
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Part 1 Strategy and planning Emergency management tools such as prior remedial contingency planning and a designated task force help those responsible for emergencies perform critical tasks confidently, effectively and efficiently John W. Wright, John W. Ely and L. Flak (former Wright, Boots & Coots employee) Blowout Advisors, John Wright Co., Houston This article is the first installment of a series designed to help operators understand and manage blowout control and intervention. Articles will be authored by individuals from various companies who are authorities in a particular field and will be presented in approximately the order outlined here.
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Operators need blowout contingency plans (BCPs) and blowout task force (BTF) organizations to facilitate blowout control. Loss of experienced personnel combined with increased regulatory oversight require that operators carefully plan how to accomplish blowout control. There are two opinions among operators about detailed contingency planning. Those who have never needed it avoid the issue with faint praise and lip service. Those who use it say that good organization and a well-crafted plan are key to success and more important than equipment, theory or individuals.
BACKGROUND Recently, the oil industry has been under tremendous pressure to operate more efficiently, which led to massive in-house reorganizations, decentralization with fewer specialists and closer risk sharing with drilling contractors and service companies. Fortunately, blowouts are less common, because modified company organizations make replacing lost experience difficult and impractical, if not impossible. In view of environmental and safety issues faced by operators today, lost experience makes it imperative for operators to have contingency plans detailing how blowout control should be managed on a corporate or "world-wide" level, and in local operating areas. This need first re-surfaced in the North Sea in 1990. After some major North Sea blow outs over about two years, operators and regulatory authorities began to re evaluate emergency response plans to ensure that lessons from these events were incorporated by all operating companies. This study indicated that all operators had plans for responding to immediate emergencies of personnel evacuation, firefighting, and oil spill containment, but few were prepared for regaining control of a blowout. Probability of a blowout might be small, but consequences can be catastrophic, so additional "problem solving" BCPs and BTFs are being implemented. Operators and regulatory bodies are investigating strategies to increase overall preparedness through contingency plans aimed specifically at regaining control of blowouts. This effort includes surface, subsea and sub surface intervention. Lack of planning and poor management has resulted in concession loss, loss of multi-well platforms, relief well blowouts and other mishaps. A good plan can help replace lost experience.
PHILOSOPHY Operators must first define a corporate philosophy for blowout intervention response and management, Fig. 1. Will projects be managed locally or by a corporate team? Can local districts manage blowout control operations and continue normal operations? Since insurance claims are generally not paid until blowout control projects are completed, how will local districts finance and handle potentially massive capital expenditures? Questions like these drive the initial effectiveness and efficiency of blowout control operations and the strategy behind how to proceed. Strategy and philosophy should be structured on a worldwide basis, but tailored to each operating area, depending on local resources and magnitude of emergency. The importance of these decisions should be equal to, and coordinated with, other corporate crisis management strategies such as those for large oil spills.
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Once sufficiently developed, the strategy should be reviewed and approved by top management. This step is critical to ensure that well thought out local plans do not get short circuited by corporate vetoes in a crisis.
BLOWOUT CONTINGENCY PLANS Successful planning and execution of complicated blowout intervention operations requires careful coordination of specialized technical disciplines. Developing a strategy is an iterative process, which requires evaluating alternatives, analyzing risks and tradeoffs before reaching agreement between operator, partners and regulatory authorities. Decisions carry substantial safety, environmental and economic implications. Persons or companies responsible for intervention can perform with confidence if proper remedial contingency planning is performed. Blowouts and subsequent intervention techniques are inherently different, making it impractical to cover all possibilities even in specific plans and execution procedures. However, structured guidelines with examples are essential to avoid overlooking critical steps in development of a final strategy for blowout control operations, where many decisions are made under stressful conditions. There are two BCP types, general and specific. General plans are strategy manuals without specific well or site information that outline how a particular operator will respond to blowouts. They are used as a training guide or workbook for developing specific plans. Specific plans use strategy from general plans for particular areas and blowout scenarios, and go through the complete intervention process on paper. Effective BCPs should include the following: Emergency BTF management-Organization and job descriptions; mobilization priorities; Initial procedures and instructions; Pre-qualification of critical equipment, personnel, contractors and suppliers; data acquisition needs for site sur vey and files; Safety, documentation and audits; emergency classifications, risks and consequences • General intervention strategies- Relief well or surface control • Blowout scenarios-Define and classify critical wells and structures based on subjective risk assessment by local management and advisors. • Specific intervention strategy- Identify relief well and surface needs for hypothetical blowouts on critical structures and exploration wells. • Logistics and support-Detail and source equipment, material and ser vices requirements based on scenarios and local capabilities. • Drilling and completion procedure audits-Review and critique well plans and risks, summarizing possible corrective measures, anticipated geology and reservoir conditions. If possible, drilling rigs to be used are reviewed and well control equipment is listed. • Blowout prevention-Well control inspections of ongoing drilling operations, listing results and recommended corrective action. • Appendix-Include items useful if a blowout occurs (wind rose, current data, surface topography maps, local water sources, etc.). •
Response plans must include directives for activating intervention BTF, and mobilizing or designating a project manager. Blowout intervention projects pose special problems unique to hazardous operations. Any number of blowout scenarios and unforeseen challenges can occur. BCPs are a pre-crisis planning process to gather, based on existing experience, available input on assumptions and strategy to reduce uncertainty. A systematic planning strategy must be adopted to evaluate risks.
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The first priority and single most important factor to assure successful blowout intervention is to quickly organize a focused team and manage the right mix of operational and technical professionals. Most problems can be attributed to misconceptions, and lack of communication, leadership and experience, rather than technical factors.
BLOWOUT TASK FORCE A properly structured BTF is key to controlling blowouts. BTF organization depends on location, blowout classification and other factors. Is it a simultaneous surface and relief well operation? Is it a platform, in deep water? Is it oil pollution? What is the project manager's background? What immediate resources are available? What blowout and relief well specialists will be used? Support of other ongoing operations must be considered. Night operations on relief wells or snubbing jobs, logistical, fabrication and maintenance operations must be considered. Task force members should be solely dedicated to blowout control and may need relief. Critical BTF team members should be pre-specified for each district. Fig. 2 shows a BTF organization chart for simultaneous surface and subsurface blowout control operations. A BTF mobilization plan is needed. This should include who activates a BTF (VP operations, area manager, drilling manager). The first step is to select the project manager and mobilize a blowout specialty company. Once in place, the project manager assists in selecting and mobilizing corporate technical, relief well and service company specialists. A team is formed to analyze the blowout situation and devise an intervention strategy. Once a strategy is chosen, the team and over all organization is reorganized to accomplish the task. Specify the best company people (line and research) and locate top out side specialists. Make emotional decisions now. Hear out vendor proposals and prices. Select a firefighter, mud company, relief well specialist and directional drilling company, and logistics and special service vendors. Tell chosen companies they have been selected and require them to be pre pared. Pre-need arrangements distribute necessary incentives and encourage service companies to make contingency plans. This ensures quicker, better decisions from qualified, motivated personnel.
Table 1. Offshore site survey data
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General Area
Well Specifics
Platform or structure damage Overall situation (stable or degenerating) • Wellhead and conductor condition (vertical) • Wellhead access (easy or possible) • Debris removal required • Sea depth, visibility, currents and waves • Current weather conditions • Surface vessels on location • Available surface equipment • •
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Blowing wells and wells on fire Blowout fluids and gases Video of blowout condition and intensity • Blowout fluid exit path description • Bubble plume description (subsea blowouts) • Heat radiation estimates • Pollution and oil spill summary • Bathymetry and shallow seismic (1 mi. radius) • • •
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Safety and risk considerations
Video and ROV information
BLOWOUT DATA ACQUISITION The next step, after organizing the BTF, is description of the current situation and events leading up to the blowout. This requires careful data analysis by different specialists, particularly in underground or subsea blowouts. Accurate information is critical, if an appropriate, timely strategy is to be devised and implemented. It is better to spend a few days analyzing data before intervention operations than to react immediately with assumptions. To facilitate analysis, certain data needs to be quickly gathered and properly documented while organizing the task force. This can be divided into two functions, office and field or site survey. Immediately after blowout, a site survey is needed to determine BTF requirements and extent of damage, fire and pollution extent. In the office. Engineers and technicians can start compiling data, well schematics and comprehensive reports on events leading up to the blowout. Then update installation drawings, highlighting damage, changes and areas where surveys and data collection are required. Site surveys. Project managers should appoint a safety coordinator familiar with the platform or rig as quickly as possible. He is responsible for assuring site survey crew safety and monitoring all plans, activities and safety equipment before proceeding. Initial concerns are fire, poisonous gas, explosion hazards (from accumulated combustible gas, processing equipment, fuel and wellheads), structure stability (degenerated by heat and explosions), diving and other hazards. Crews may not be able to re-enter the platform or rig immediately to ascertain condition or gather data. Experienced firefighting and blowout teams should be used in survey crews and persons responsible for coordinating surveys and data acquisition should be named in BCPs. Table 1 lists site survey data from an offshore blowout. Main files. A project work file should incorporate all relevant project documentation. Well organized, clearly marked and up to date files should be available to the task force at all times. Copies should be made of all important documents and kept in a separate file in case of loss. The working file should include the following:
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• • • • • • •
Correspondence with authorities, partners and insurance companies Meetings with authorities, partners and insurance companies Documentation organized by task or project Reports in draft and approved form, updated and organized by revision Programs and procedures Project reports Presentation material.
Modifications may be made to fit existing document control structures. Document control. A major blowout intervention project hastily organized in a few days with many people involved generates hundreds of documents. If not controlled from the beginning, documents may become lost, disorganized, late, out of order; or they might not get to the proper people. This means personnel may not be working from the same or latest plans, creating technical confusion. In addition, insurance companies, government or regulatory agencies, quality assurance and safety managers, and top management of the operating company and partners require certain documents to make major decisions. Reports submitted outside the task force should be routed through document control. Document control will transmit them with a formal transmittal. All outside correspondence or reports should be authorized by the project manager. Formal reports to be handed out in meetings with people from outside the task force should go through this process before the meeting. Audit trail. A proper audit trail should be set up at the beginning of the project before things get out of hand. A document control center should be established to serve only the intervention project. There should be at least one person in this group capable of under standing the documents, so that they are sorted, passed on and filed correctly. Control responsibility should not be left to unskilled clerks. Document control duties include: • • • • • • • •
Ensure that documents are delivered, registered and filed Distribute documents to task force members Maintain project working file Establish a filing index Assist project team in document control Keep complete files Search for missing documents Others, as required by operators or circumstances.
OTHER TOOLS The BTF must look at the short term and concentrate on immediate problems and current operations. On major blowouts, particularly in instances of public evacuation and pollution, operators should establish emergency response rooms and emergency groups independent of BTFs. Emergency response group. This group looks at long term plans, concentrating on all other aspects of the emergency, media coordination, plan critiques and reviews. Emergency response groups must see the "big picture" and consider alternative strategies, planning what to do if current plans do not work. It should be a small group of local and corporate managers with representatives from working interest partners who meet regularly with BTF project manager and blowout advisor. At least one group member should have a strong drilling background. Meetings should be short with organized agendas that include:
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• • • • • • • •
Summary of current well status, pollution and publicity Summary of current BTF and well control activities Summary of current expenditures and long term cost forecast A listing of current needs and problems A review of last meeting, remaining questions and action steps Long term review A new list of questions and actions Emergency Response Group and BTF assignments based on new lists.
The first four items are generally presented by BTF project manager and blowout advisor. Emergency response rooms should have all blowout data obtained by the BTF and a copy of the project work file. Trial runs. After a local district pre pares a BCP and determines BTF members, a drill based on a probable blowout scenario detailed in the BCP is recommended. Specific circumstances and data from an actual prior blowout can be used effectively as the basis for this drill. Technical background can be provided to make drills realistic. In one instance, BTF participants were assembled on a workday without prior notice and no initial knowledge that this was a drill. Actual video and photographs obtained from a past blowout were used. Circumstances of that blowout were applied to a well that was currently drilling. The BCP was consulted, and contractor/vendor call-outs were made based on initial mobilization plans. Review.A critique session is held after a drill. Insight gained from trial-runs about the plan, team effectiveness, critical services, equipment and material availability is incorporated in an iterative process. BCP and initial mobilization plans are changed according to what is learned.
BLOWOUT RESPONSE Once a BTF is organized and as much relevant data as possible has been gathered, the team can evaluate various interventions. Each alternative and critical factors for making comparisons must be understood by the team. Implementation. Once intervention options have been analyzed and a course of action chosen, the BTF should be reorganized to implement the plan using available resources. This means organizing several small, sub-task forces (surface and relief well) for detailed planning, equipment procurement, modification and manufacturing, operations, kill procedures, safety, documentation and administration. Many blowout problems can be traced to poor initial decisions. Pre planning avoids competitive pressures and personal attachments, allowing operators time to review competing proposals. While reviews are underway, an organized team is already moving toward a possible solution. Example response. Kuwait 1991, the largest blowout control operation in history, was pre-planned. In October 1990, Kuwait Oil Co. (KOC) recognized that Iraq would blowup oil wells. BCPs were made in the Houston offices of O'Brien-Goins-Simpson. KOC's drilling manager Saud Al Nashmi was BTF project manager, and Larry H. Flak was blowout advisor. Plans based on several scenarios listed required services, materials and equipment. Blowout control budgets were prepared, and contracts were negotiated and signed with critical service, supply and support vendors before Iraq blew up the wells in late February 1991. Effectiveness of pre planning efforts was demonstrated by the capping of all 698 blowouts between March 4 and November 8 1991 (250 days).
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Blowout Control Technical Reference
Part 2
Logistics 11
Part 2
Logistics Special services are often unfamiliar to operators and may not be available locally. Critical support and transportation are best managed by pre-planning to identify service, material and equipment needs. Vendors can be pre-qualified and contracts are signed in advance John W. Wright, Blowout Advisor, John Wright Company, James A. Tuppen and L. Flak, Blowout Specialists, Boots & Coots, L.P. Except for organizing blowout intervention teams, the most complicated and typically overlooked components of implementing emergency projects are services and equipment logistics. Many required services are specialized and may not be available in the region. Knowledge of these services and companies that provide them may be unknown to typical company engineers with minimal experience in blowout control. Figure above. Derrick barge in use during well capping operations. Large multi-service vessels (MSVs), generally available only in the North Sea, support surface blowout control operations on offshore structures with cranes, fire pumps, monitors and living quarters. MSVs, large cranes or stimulation vessels simplify surface blowout control intervention.
INTRODUCTION An expensive and time consuming learning curve, often with disastrous results, has been evidenced in projects that used standard services beyond their capabilities, overlooked details that became insurmountable obstacles, included incompatible services, and neglected to identify applicable specialized and non-specialized vendors. There are, however, methods to reduce problems associated with logistics and support for any project. During preparations for fighting Iraq in the Gulf War, General H. Nor man Schwarzkopf understood that without superior logistics and sup port, coalition forces could not be properly fielded, which would pro long the war and result in greater casualties. "The fellow . . . responsible for making sure soldiers had food, clothing, shelter, transportation and bullets-was Major General Pagonis . . . an Einstein at making things happen (2)." After the Gulf War, Kuwait oil well fires presented a logistical and sup port challenge on the scale of the problem faced by General Pagonis. In 1990, General Pagonis was promoted to four stars and later, in 1991, he replaced General Schwarzkopf. Pre-planning for the Kuwait fires included sourcing services, equipment and materials, pre-contracting, communication and transportation. Later over 520,000 t of supplies were moved to Kuwait to fight fires.
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SERVICES, EQUIPMENT AND MATERIAL Oil company civil, materials, transportation and logistics departments need to review detailed blow out contingency plans to determine how each section will address defined support requirements (Part 1). Operators need dedicated support personnel working in transportation, material acquisition, logistics, contracting, accounting and communications if a major blowout occurs. Table 1. Underground blowout control requirements Description • • • •
cementing pump and cementing lines cementing batch mixer or additional mud mixing tank cased hole wireline unit pressure/temperature log, perforators, drill collar severing tool, rate gyro,
TDT possible additional stimulation pumps (higher rates and/or pressures required) • centrifugal pumps (mud transfer and circulation) • suction hoses and mud transfer lines (additional mud tanks and water pit) • sack cement and pure bentonite for bentonite - cement - diesel oil - plug • medium & coarse LCM materials (KwickSeal, mica, nut plug, ground CaCO3) • additional mud products for quick mix mud (gel, caustic, barite, dispersent) • additional water supply ( possible additional water wells and water storage pit) • new seismic to map gas flood front (sustained high rate gas flow) • re-survey surface location from fixed reference point (possible relief well) • rate gyro run on drill pipe for better relief well target • initiate relief well planning (severe gas flow, potential loss of surface access) • additional mud storage tanks • possible snubbing unit and tools • inflatable packer (unable to dynamically kill, hole in casing) • handheld radios for site communication •
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blowout advisor
Support and services. An important blowout team member is the drilling contractor. They have local experience and know how to acquire key services, equipment and materials that are available locally. Rig crews are needed to assist blowout specialists. Operators should hold a pre-planning meeting with the rig contractor to discuss the following: • • • • • • • •
Third party billing and purchase orders Cash flow assistance and local vendor credit Increased pay for hazard duty and difficult work Added staff from contractor to handle logistics Increased base camp space Spare equipment (BOPs and choke manifolds) Welding and fabrication Oilfield supplies. 13
Equipment and material. The key to successful blowout control is fast and efficient mobilization of required support. Civil equipment (dozers, cranes and front end loaders) and trucking should be obtained locally. Air freight for this equipment is avail able, but costly. Winch-equipped dozers will be needed, but may be hard to find in some areas. Winches can be air freighted in with firefighting equipment. Offshore blow-outs require additional marine equipment (supply, off shore crane and stimulation vessels; anchor and diver support boats; and ROVs). Large multi-service vessels (MSVs), generally available only in the North Sea, are designed to support surface blowout control operations on offshore structures with cranes, fire pumps, monitors and living quarters. If available, MSVs, large cranes or stimulation vessels simplify surface blowout control intervention, Fig. 3. In many ways surface blowout control onshore in remote areas can be more difficult. Water is needed to control fires, and protect men and equipment. Transportation and support issues are complex. Tables 1 and 2 list example requirements for onshore blowouts. The lists are not complete, but can be used for reference. Table 2 - Surface Blowout (No Fire) Requirements Safety & Medical • • • • • • • • • • •
H2S / Paramedic services: detection and breathing air equipment, ambulance medical evacuation services ( helicopters, jet ambulance) medical services (burn - trauma care capability) flare pistol or rifle with flares large wheel mounted fire extinguishers cotton rags drinking water location rest and control trailer for well capping specialists video and still photographer to record operation location security and road blocks handheld radios, 4 mobile radios, additional telephone and fax line
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evacuation of local population and livestock
Services • • • • • • • • • •
wellhead equipment and service technicians well capping specialists (possible requirement for fire pump for protection) blowout technical advisors dedicated materials coordinator dedicated operations documentor and cost engineer welding / fabrication contractor machine shop: to provide custom tool fabrication and modification; in-country delivery / trucking services; pumping / cementing services water well driller, casing and pumps, pit liner (water supply requirement)
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possible snubbing and hot tap services and associated equipment
Equipment and materials civil works contractor to provide: dozers excavator , front end loader, maintainer, dump trucks, water trucks, possible 200 to 300 ton crane (for >100 foot set-back with 50,000 pounds of pick-up), probable 150 ton hydraulic road crane, lube/fuel truck, forks for loader, air compressors and associated support personnel and skilled operators • oil field rental tool equipment •
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• • • • •
fabrication steel including angle iron, H-beams, steel plate (various thickness), tubing dry ice and insulated transport box portable generators and light plants common oil field supplies (ex: rope, chain, hooks, clamps, gauges) diesel powered centrifugal pumps for mud and water transfer
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reel of 1-1/8" soft lay steel cable for snub down lines and winches
PRE-QUALIFICATION The expertise of qualified personnel and companies can prevent catastrophes. Blowout intervention projects are rare and experience from these specialized projects is invaluable. A justifiable premium is applied if experts are used, but the higher cost for special services can be insignificant compared to the consequences of a disaster. One way to minimize logistics problems is to pre-qualify special services, equipment and contractors. A pre qualification plan enables operators to identify and source required services. Although time consuming, this simple task can have tremendous positive effects on project organization, coordination and implementation. Pre-qualification of services and equipment is a cognitive, rational and dynamic process essential for efficient operations, but it is not a new idea. In typical E&P projects, the bidding process includes identifying vendors, establishing requirements, and evaluating services and costs. In some cases, final decisions are dependent only on low bids; not on adequate experience, competence, and ability to deliver goods or services. Most judgments however, should and often are made on technical capability versus project economics. Evaluations. Prospective services should be evaluated to identify and contract the most qualified suppliers. Scrutinizing service prices should be a secondary consideration. This requires an approach that operators are typically not accustomed to. A very interactive relationship must be established with vendors to achieve an unbiased decision making process. Personal visits by operators to various companies are necessary. This can be delegated to several people, but only one individual should evaluate all prospective suppliers of a particular service. Evaluators should have a good working knowledge of this specialty through experience or investigation and should approach vendors in a formal manner. Vendors' corporate, regional and local organizations should be included. Some companies have formal or informal groups of specialists (troubleshooters) that may not be known at local levels. A listing of these special groups and members should be made. Resumes and references of individuals and groups should be obtained and evaluated. Investigation of performance and work quality is key to this analysis. Checking references provides direct insight into service quality and individual qualifications. When experienced personnel are incorporated into a team, effective plans evolve. A proper plan implemented by qualified people produces success. A corporate and local-level approach maximizes evaluation effectiveness. Specialized services (firefighting, blowout intervention engineering, electromagnetic ranging, blowout capping and snubbing equipment) can be assessed by a group of corporate experts for company wide approval. Local operating areas can evaluate regional level services. If company wide approved vendors are chosen, local organizations can establish specific lists of the most qualified vendors for a region.
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Contracts and agreements. Pre qualification is an iterative process represented by the logical design path shown in Fig. 4. The first step is to define required special services and identify qualified vendors that provide these services. An unbiased evaluation phase is instituted and vendors are selected. Contractual agreements are made to maintain a team relationship and create a sense of preparedness within the team. Operators must maintain a list of vendor experts and contacts that will be notified in an emergency. A review of vendor status should be performed periodically to insure that the best people, equipment, and services are available. To maintain effectiveness, pre-qualification must be an ongoing process. A crisis is not the time for evaluation or re evaluation. Follow-up. Emergencies require attention to life saving, personnel rescue, protecting property and investments, and problem resolution. Time is one of the few constraints of blowout intervention, so response time must be minimal. Continuous monitoring of available special services is mandatory. Operators should carry out the following: • • • • •
Maintain current contact lists Identify team members Specify critical equipment and services Require immediate updates on vendor contractual and non-contractual condition changes Re-evaluate currently qualified vendors regularly.
SHIPPING AND TRANSPORTATION Mobilization. Blowout specialists are mobilized to begin survey and location preparations and define requirements at the well site within 24 to 48 hr of a blowout. Equipment follows this group to the blowout. Blowouts in remote areas and outside normal activity-intensive oilfield operations areas require extensive use of inter national air freight and local marine or land transport. Long-haul shipping. It is possible to air freight firefighting, snubbing and well capping equipment any where in the world. This reduces the need to stock specialized equipment required for rare onshore burning blowouts. Offshore blowouts may require air transported equipment, but a 72 to 96-hr time window is generally sufficient to meet control schedules. Availability of large Russian cargo aircraft significantly improves transportation options. The Antonov AN 124 aircraft can transport 140 metric tons (mt) of cargo and is available for commercial charter, Fig. 5. This type of plane was used to ship three Cat D9N bulldozers with winches per flight from Peoria, Illinois, to Kuwait in 1991. Only the U.S. Military Air lift Command with C5A aircraft, which are not commercially available, can come close to this capability. AN 124 aircraft require no specialized air cargo ground handling and offloading equipment. One AN-124 flight can transport almost all of the specialized intervention and control equipment for a major onshore blowout, whereas two or more 747 flights would be required . Nose-load 747 cargo configurations are more available than AN-124 air craft, but have limited payload (about 80 mt), cargo clearance (7 ft 11 in. maximum height) and require scissors lift offloading equipment that may not be available. Smaller Hercules L-110-20 aircraft are available with a payload of about 34 mt and can land on smaller runways in remote areas. The Russian Ilyushian Il-76 aircraft is also commercially available. It is equivalent to the Hercules, but with a higher payload capability of about 45 mt. Hercules L110-20 and Il-76 aircraft do not need special offloading equipment. Generally,747 and AN-124 aircraft are limited by internal volume capacity not payload. Fig. 4. Pre-Qualification is an iterative process as represented by this logical design path. 16
Local transportation. Helicopters and VSTOL (very short takeofflanding) aircraft may be needed for remote onshore locations. These air craft facilitate transport of men and small equipment and are effective for evacuation of medial emergencies to hospitals. Local ground transportation should include wellsite personnel, base to wellsite transport and heavy equipment transport. Large oilfield platform trucks (Kenworth 953) with winch and tail roller are useful and can replace dozers in certain locations and applications (skid ding rig or debris removal). Semi-low trailers (75 t) are required to move heavy equipment, and normal oilfield bed floats are needed for general transport.
SUPPORT BASE As in military campaigns, it is better to manage and coordinate efforts at the front line where direct control of operations can take place. No competition or communication problems can develop between rear echelon management and front line efforts if this is the case. In many efforts, field groups and main offices disagree about required actions. If blowout control and coordination is to be accomplished at the wellsite, a field support base or command center is needed. Offices, conference room, communication equipment and file storage are required. Logistical and support efforts are coordinated from this base near the wellsite. Even major offshore blowouts have been successfully site managed. Major blowouts require a field support base. Steps should be taken immediately by operators to set up a base when blowout specialists are mobilized. Onshore, bases using rig camp, local production facilities or rental trailers have been used. Off shore bases may be an adjacent rig, platform, MSV or crane barge, Fig. 3.
COMMUNICATION International phone and fax communication is needed, as well as base to-wellsite radio communication. Generally, a communication system exists to support operations prior to the blowout. This communication system forms the nucleus for an expanded system that is needed to control a blowout. Pre-planning for expanded communication capability when setting up the system for normal operations is needed. Capability to have additional telephone lines, microwave and radio frequencies should be built into original communication plans for an area. Communication equipment and computers require an uninterruptible power system (UPS) if generator power is used. Onsite. Site communication is best handled with 5-Watt, intrinsically safe handheld radios. Head sets that work under hard-hats in high noise environments are available. Many radios and multiple channels may be required for large operations. Use of repeaters can give low-power FM radios good range in flat areas. Long distance. If the support base is distant, it may require repeaters or larger 25 to 30-Watt radios that work with 5-Watt radios, but have greater range. More powerful FM radios are generally used in base or vehicle mounts. Single side band (SSB) or short wave radios can communicate over greater distances. Use of radios and allowable frequencies are con trolled by many governments. Operators should fully understand local regulations . International. Fax capability over radio exists and can be effective if the right equipment is used. If existing international phone capability does not exist at the well site, portable satellite systems are available for rent or purchase that can be carried in by blowout specialists. These systems are remarkably compact and can be checked as luggage. Essentially, these systems are an international phone and fax in a suitcase.
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FINANCIAL ISSUES Fig. 5. Availability of large Russian cargo aircraft significantly improves transportation options. Antonov AN-124 aircraft can transport 140 mt and are available for commercial charter. Blowouts can result in massive payments to many contractors and suppliers. Operator financial and accounting departments need to provide support for handling new con tracts as well as control of immediate and potentially large cash flows out of the company that are over and above normal operating budgets. The specialist blowout and fire fighting companies generally cannot sustain extended blowout control operations without prompt payment. Money will be needed to mobilize men and equipment and for air freight. For example, 747 aircraft cost over $250,000 per flight and payment is required up front. Letters of credit and other financial guarantees may be needed. Cost control is not improved by delayed payments, which can result in late charges and inflated prices, and make it difficult to obtain required support. Emergency cost control procedures should be set up prior to a blowout. Contracts need to be in place ahead of time for potential service, material and equipment requirements for possible blowout scenarios within the company's operating region. Invoices can then be checked against contracted rates. Pre-qualifying vendors for specified services, materials and equipment, and establishing call-off con tracts is the final step in blowout response preparations. Financial terms and conditions can be settled in advance along with contractual issues. It is critical for operators to under stand that agreements for emergency services are significantly different than contracts for normal operations. The basic difference is that start, duration and contract value for emergency services cannot be predicted in advance. Costs normally borne by contractors cannot be factored into rates as is the case for standard service contracts. Taxes and costs of special insurances (war risk, political risk, etc.) must be covered in addition to contracted fees. Blowout services contractors are responsible for their staff, but not much else. Logistics and support are critical areas for successful blowout control. The financial burden of a potential blowout control operation needs to be evaluated. Blowouts have resulted in bankruptcy of operators insufficiently capitalized or insured to deal with a disaster.
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Blowout Control Technical Reference
Part 3 Insurance
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Part 3
Insurance For the assured to be prepared for the emergency and be adequately covered, correct policy wording on Control-of-well coverage under OEE or EED 8/86 forms needs to be worked out in advance Sam J. Salvato, Jr., President, Matthews-Daniel Co., and Larry H. Flak, former Wright, Boots & Coots employee, Houston, Texas This article discusses the important subject of insurance-what is available, what can be covered and why operators and contractors need to know this. Specific discussions include: 1) role of the adjuster and the mechanics of "how you get paid," 2) two basic policy forms, OEE and EED 8/86, now avail able, and 3) evolution of well control coverage and important definitions. The article concludes with some comments and cautions on what might happen to this coverage in the future.
INTRODUCTION It is the middle of the night and the phone rings. It is the drilling foreman at your new location and he advises you that the well is blowing out. Numerous thoughts race through your mind, and your first reaction, depending on your company duties, is to visit the wellsite or get to the office to obtain full details. Then, you begin to realize the seriousness of the well remaining out of control, and it becomes clear that, in addition to controlling the well, you may be facing potential liability claims in respect to pollution and third party damages. Your thoughts then turn to remedying the problem and implementing a response as soon as practical, to mitigate the loss. Through discussions with other personnel, the decision is made to bring in outside control-of-well experts, following which, control procedures are designed. Also, by this time, and of course assuming you are insured, you have recognized the need to advise your insurance agent or broker so they, in turn, can report the incident to your insurance carriers. Unfortunately, it may only be at this point that you begin to realize how unfamiliar you are with coverages purchased and the mechanics of pursuing claims on the relevant policies. Here are some discussions on steps that can be taken to design the right insurance in advance, and know how to implement it.
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PREPARING FOR THE CHALLENGE Of the many problems plaguing the oil/gas industry, probably none rate as dramatic as a well out of control. Blowouts throw fear into the public, and because no one is really immune to their devastating effects, drilling is a politically and environmentally sensitive issue. It is becoming further apparent that, as intensified petroleum exploration operations progress toward complex and adverse environments such as deeper waters offshore and more inhospitable, remote and ecologically sensitive terrain onshore, the potential for accidents and mishaps increases. Given the legal responsibilities and liabilities that operators and drilling contractors are exposed to, both may be forced to endure financial burdens associated with a blowout. Without sufficient resources to deal with these responsibilities, insolvency of certain involved parties could be nearly inevitable. Historically, most operators and contractors have turned to insurance as the means for demonstrating financial responsibility. Responsibility of the assured. Unfortunately, it is not unusual for operators/drilling contractors to only become aware of deficiencies or limitations in their well control coverage while actually experiencing a blowout. It often happens that much of what an assured initially understands about scope and degree, or lack thereof, of policy coverage is through discussions with a loss adjuster appointed by insurers once a potential claim is notified. The role of the adjuster, however, should not include introduction of the assured to their policy workings. Once operators and contractors recognize their exposure to risks associated with drilling operations, they should, through liaison with their insurance agent/broker, formulate an insurance program. Close attention should be paid to types of coverage available and, of course, applicable limits and retentions in the event a loss is sustained. It goes without saying that policy limits and retentions should reflect the ability of individual companies to absorb a loss while, at the same time, protect their assets. Preplanning will help alleviate situations in which the assured, having notified a well control claim, is faced with the prospect of being unable to recover the full amount of expenditure for remedial operations thought covered. The insurance loss adjuster. As the adjuster plays an important role in an assured pursuing a claim, a brief explanation of the adjuster's role is in order. Under normal circumstances, insurers will confirm the appointment of a loss adjuster immediately following loss notification. The adjuster would then contact the assured and, if required, visit the casualty site and establish a rapport with the contractor/operator. This early involvement, in addition to allowing a preliminary loss assessment, provides the opportunity to address, with relevant personnel, the need to maintain records and documentation for downstream claim settlement purposes. Also, the adjuster may aid in developing a cost accumulation system in a manner that will serve all parties' interests. This would tend to expedite processing and payment of legitimate claims. For the most part, the adjuster will concentrate on issues concerning insurance aspects of the event-that is to say, make a determination as to loss cause and magnitude so as to ascertain various insurance coverages which may be affected and to what degree. Further, when possible and depending on circumstances, the adjuster may be in a position to contribute to planning/implementation of the remedial program. Finally, early involvement and continuous monitoring of the event by the adjuster is crucial as it affords the opportunity to quickly ascertain and comprehend the mechanics of the situation. This ensures that reporting of the event to the underwriters is factual and provides that any subrogation possibilities, which benefit both policy holder and underwriter, can be quickly identified. The adjuster's input with regard to insurance concerns is often beneficial to the ultimate course of remedial action being considered by the policy holder.
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Responding to concerns. Again, as indicated earlier, many assureds look to their policies for financial security and for funds as necessary to indemnify loss expenditure. This being the case, and depending on monetary resources available to an assured, some first questions confronting the adjuster are: • • •
How much money do I get? What do I have to do to collect it? When do I get paid?
However, before such questions can be answered, the extent of insurance coverage must first be addressed. To accomplish this, one would determine contractual relations existing at the time of the event and applicability of specific policy wordings. Once this is achieved and coverage confirmed by insurers, reviewing and approval of invoices detailing expenditures arising from the loss would eventually lead to moneys being made available to the assured. Such settlements could come in the way of partial payments during the period the assured's claim is being reviewed/approved or through a single payment when the final claim is agreed.
CONTROL-OF-WELL COVERAGES Today, well control coverage is avail able in two basic policy forms: 1) Operator's Extra Expense (OEE), and 2) Energy Exploration and Development (EED 8/86). Over the years, other forms of insurance for energy operations have been introduced; however, most of those are no longer readily available. There are several renditions of the OEE wording; conversely, EED 8/86 coverage is primarily available under a standard form. As for sections of basic insurance coverages available under OEE and EED forms, these are similar, and are either incorporated within the body of the wordings or made available by endorsement. Primary coverages which can be attained under the forms of insurance in question are: • • • •
Control-of-well Redrilling/Restoration/Recompletion Seepage and pollution/Clean-up and contamination Care, custody and control (third party equipment).
It must be emphasized that not all coverage types are automatically included in OEE and EED forms. There are other coverages such as Making well safe, Underground blowout, and certain liabilities, which, depending on philosophy of the assured and nature of the operations, could be considered fundamental. Therefore, it is imperative that the assured is fully aware of coverages which can be purchased so that they can be confident their exposure to potential financial burdens is within acceptable limits. For the purpose of this article, further discussions will concentrate on only Control-of-well coverage aspects. Not to diminish the importance of the other coverages, it is normally a covered occurrence under policies' Control-of-well sections which activates the remaining coverages.
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WELL CONTROL COVERAGE EVOLUTION To best appreciate the primary difference between OEE and EED forms with respect to Control-of-well cover age, an introduction to the history of this wording is useful. It appears that specialized energy insurance cover ages originated in the late 1940s, with onshore risks being addressed by the London insurance market. Prior to World War II, there was no significant offshore drilling activity, and insurance coverages were limited to physical damage for land drilling rigs which were insured as contractors' equipment much in the same manner one would insure heavy construction machinery/equipment . However, after World War II, with capital investment in the energy field on the increase, and oil/gas operations extending from onshore to near-off shore areas, a requirement existed for innovative ideas for protecting energy exploration investments. The challenge to provide this protection through insurance was taken up by the London insurance market, which developed the specialized policies- particularly the Control-of-well coverages. The U.S. domestic market, to a degree, then followed suit. Early definitions. As best as we can determine, in the late 1940s and early 1950s, Control-of-well coverage was available under a relatively simple Lloyd's of London Standard Form which provided, inter alia: "To cover expenses entailed by the assured in regaining control of oil or gas well(s) being drilled . . . which get out of control as a direct result of the drilling of wells insured hereunder until completion of (or) abandonment . . ., caused by . . . Blowout." Interesting enough, some of the early insurance coverages did not include definitions for "blowout" and/or "well out of control." This obviously was a potential problem and did, indeed, lend itself to certain assureds taking legal action against insurers . Other policies incorporated definitions for blowouts, with emphasis on loss of equilibrium in the wellbore due to downhole pressures which exceeded that exerted by the column of drilling fluid. One such early definition of a blowout was: ". . . a condition in which a well builds up a sufficient gas pressure at the bottom of the hole and causes a rather sudden, forceful eruption or explosion which cleans out the well and causes it to go out of control." Regardless of existence, or lack, of a definition, courts routinely adopted the position that the rule for interpreting insurance contracts was the controlling factor in determining coverage, and that the definition or interpretation of a blowout which was most favorable to the assured would prevail. Example court-case definitions. There were several court cases which directed the interpretation of the Control-of-well coverage and which were often referred to during evolution of OEE wordings. One such case was Creole Explorations Inc. vs. Under writers at Lloyd's (La. 1964).3 This case involved a well which was alleged to have had a blowout on July 20, 1958. This being one of the instances where the insurance policy did not contain a definition for blowout or well out-of-control, the Louisiana Supreme Court in 1964 adopted definitions which were most favorable to the assured. In this case, the definition utilized for a blowout was: ". . . A blowout occurs whenever pressure from the formation overcomes hydrostatic pressure exerted by the mud column and forces formation fluids to the surface." The definition considered for "control" was that: ". . . the well was under control when the column of mud was balanced so that whatever operations were necessary could be performed in the wellbore hole, and that it was out of control when the mud column became so imbalanced from gas and saltwater penetrations that operations had to be stopped while the mud was conditioned or weighted up and control regained." A second case which demonstrated that courts were interpreting the policy wordings in a manner most favor able to the assured was Sutton Drilling Co., Inc., vs. Universal Insurance Co. (Fifth Cir. 1964).4 In this case, the policy defined a blowout as: ". . . a sudden uncontrollable expulsion of drilling fluid, gas, air, oil or water, from within the well erupting above the earth's surface and . . . resulting in the well getting completely out of control and . . . rendering the use of any blowout preventer equipment, customarily used, inoperative or ineffective." Given the circumstances, a jury trial concluded that there was not an occurrence within policy definitions and, therefore, no claim. However, the Court of Appeals determined that a blowout 23
had occurred and that the well was out of control to the extent that extraordinary well operations had to be implemented and routine drilling could not continue. Getting more precise. As a result of such rulings, it was becoming obvious to insurers that they would have to take steps to eliminate ambiguities in their policies. To a degree, this was somewhat accomplished by the introduction of more precise definitions. Examples of refined definitions, variations of which could be found in the subsequent Operator's Extra Expense cover, are as follows: Blowout: ". . . a sudden accidental, uncontrolled and continuous expulsion from the well and above the surface of the ground of drilling fluid in an oil or gas well followed by continuous and uncontrolled flow from the well and above the surface of the ground of oil, gas or water due to encountering subterranean pressures and resulting in the well getting completely out of control." Well out of control: "A well(s) shall be deemed out of control only so long as (when) there is a continuous flow of drilling fluid, oil, gas or water above (or below) the surface of the ground or water bottom (which is uncontrollable by the blowout preventer and/or storm chokes and/or wellheads and/or safety valves installed in or on the well)." OEE wordings. A third legal case which influenced the development of modern day OEE policy was Atlantic Richfield Co. vs. Underwriters at Lloyd's London (D.C. Tex. 1975).5 The issue in this case was not if a blowout had occurred, but when was control of the well regained? At the time of the policy period (1969/70), wordings did not include a definition for "well under control." It was Underwriters' position that, once there was no longer a blowout in accordance with policy definition and pressures could be confined within the wellbore and works implemented to eliminate the source of the pressure, then the well was under control. However, the court rejected this contention and concluded that ". . . from a practical point of view . . ." a well was not under control until workers could ". . . make the well as planned." In many policies thereafter, definitions of a well under control were incorporated with variations along the line of: "A well(s) shall be deemed under control 1) when the well(s) can be re-entered for salvage, fishing, whipstocking, or cleaning operations, or to resume drilling, or 2) when the well(s) can be plugged or abandoned, whichever first occurs...." Certain policies also allowed for regulatory authorities to confirm insurance coverage by stipulating when a well was and was not out of control. By the late 1970s/early 1980s, it was becoming common practice under an OEE policy to conclude that a blowout and/or well out of control had occurred and relevant insurance coverage triggered when there was a breach of the drilling circulatory system. Once this was demonstrated, the Control-of-well coverage continued until such time that normal and routine drilling practices could be restored. There is little doubt that coverages provided under the OEE form were interpreted to be much broader than insurers originally intended. Nevertheless, it is quite apparent that OEE wording was, and continues to be, viewed as a comprehensive cover to indemnify an assured for appropriate expenditure incurred during a period a well may be technically out of control. Changes through EED 8/86. Given the fact that underwriters continued to be held liable for claims which they never intended to cover, it was concluded in the mid-1980s that the time had come for a revision in well control insurance wordings. Also, by that time, there had become numerous variations of the OEE wording as a result of brokers wanting to market their own version of the Control-of-well coverage. Partly due to these reasons, and in an attempt to standardize that coverage, an undertaking by representatives of the London insurance community led to introduction of the EED 8/86 wording. Unlike the previous Control-of well wording, EED did not incorporate a blowout definition, but, instead, addressed the cover in terms of definitions for wells 1) out of control, and 2) brought under control.
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The definitions for well out of control are as below: "Well out of control: For purposes of this insurance, a well(s) shall be deemed to be out of control only when there is an unintended flow from the well(s) of drilling fluid, oil, gas or water above the surface of the ground or water bottom, 1. Which flow cannot promptly be: Stopped by use of equipment onsite and/or the blowout preventer, storm chokes or other equipment required by the Due Diligence and Warranties clauses herein; or • Stopped by increasing weight by volume of drilling fluid or by use of other conditioning materials in the well(s); or • Safely diverted into production; or •
2. Which flow is declared to be out of control by the appropriate regulatory authority. "Nevertheless and for purposes of this insurance, a well shall not be deemed out of control solely because of the existence or occurrence of a flow of oil, gas or water into the wellbore which can, within a reasonable period of time, be circulated out or bled off through surface controls." "Well brought under control: A well(s) deemed out of control in accordance with (the above) . . . shall, for purposes of this insurance, be deemed to be brought under control at the time that: 1. Flow giving rise to a claim here under stops, is stopped or can be safely stopped; or 2. Drilling, deepening, servicing, working over, completing, reconditioning or other similar operation(s) taking place in the well(s) immediately prior to the occurrence giving rise to a claim hereunder is (are) resumed or can be resumed; or 3. Well(s) is (are) or can be returned to the same producing, shut-in or other similar status that existed immediately prior to the occurrence giving rise to a claim hereunder; or 4. Flow giving rise to a claim here under is or can be safely diverted into production; "Whichever shall first occur, unless the well(s) continues at that time to be declared out of control by the appropriate regulatory authority, in which case, for purposes of this insurance, the well(s) shall be deemed to be brought under control when such authority ceases to designate the well(s) as being out of control." As was the case with the OEE wording and as referred to earlier herein, additional coverages such as Underground blowout and Making well safe were also made available under the EED 8/86 form. Coverage differences. When comparing EED 8/86 wording to that under the OEE form, it is difficult to conclude that they provide the same degree of coverage. With emphasis in the EED wording for determining whether or not a well is out of control being put on status of flow from the well, it is easy to conclude that EED wording is not a comprehensive well control coverage. Routine interpretation of this wording and application to numerous claims have, for the most part, established that EED wording provides limited coverage to the well control remedial program to the extent that flow from the uncontrolled well is stopped or can be safely stopped. That is to say, it is arguable that Control-of-well coverage under EED wording cannot be triggered with coverage only being in effect so long as there exists a flow from the well. There are, of course, exceptions to this; the obvious being when the appropriate regulatory authority deems otherwise. Regardless, it should be accepted that scope of Controlof-well coverage provided under EED is much more restrictive than that in OEE wordings.
FUTURE COVERAGE, CONCLUSION
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At the end of 1991, and during early 1992, the Joint Rig and Associated Business Committee of Lloyd's agreed that it should actively encourage and promote a return to utilization of standard insurance wordings in the market. EED 8/86 was the first to undergo such a review, with the intent being to formally introduce the revised wording into the marketplace beginning early 1994. It would not be appropriate at this time to comment on specific revisions and modifications to the EED form except to say that the basic coverage concept, being that the wording is something less than a comprehensive insurance policy, has not been abandoned. In fact, an attempt has been made to emphasize just this point and to -further clarify scope and degree of coverage. Also, it is becoming even more obvious that underwriters will be looking to more accurately assess their exposure to risk and establish some predictability in the interpretation and application of the wording to potential well control related claims. Notwithstanding, it appears inevitable that, given the nature of the insurance market, certain variations of the OEE wording will continue to be available, although perhaps on a much more limited basis. In conclusion, from the above, it is apparent how assureds who are not totally familiar with the workings of the Control-of-well coverage would react to the situation should they find themselves faced with obvious well control expenditure not being recoverable, given their policy is something less than what had been envisioned! We cannot overemphasize the importance of an assured being fully aware of the types of Control-of-well coverages available and workings of the relevant wordings. This can best be achieved through close, in-depth communication with prospective insurance agents/brokers. This is the only sure way of being confident that the appropriate cover- as necessary to meet your financial objectives-is being purchased, and at acceptable rates. Finally, although the Control-of-well insurance coverages have been made available to the industry in some form for more than 45 years, we cannot take for granted their existence in the future. Accordingly, it is imperative that all interested parties work together to insure the perpetuation of this cover at realistic premiums.
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Blowout Control Technical Reference
Part 4 Documented Contingency Plans
Part 4
Documented Contingency Plans 27
The first step to reduce vulnerability posed by a potential blowout is a documented emergency management and response system that will advise you of initiatives that must be addressed John W. Wright and James F. Woodruff, Blowout Advisors, John Wright Co., and David Thompson, Blowout Specialist, Boots & Coots L.P.
This article discusses Blowout Contingency Plan development with discussions on: 1) document scope and content- why a BCP is needed and what it should cover, and 2) BCP organization-how a typical fivepart plan is developed, including example outlines. Also described is the need for a separate Workbook to backup the BCP organization and keep it up to date. Part 1 of this series discussed strategy and planning, and introduced the concepts of Blowout Contingency Plans (BCPs) and the Blowout Task Force. Two types of BCPs, general and specific, were defined and what an effective contingency plan should include was listed and described. 28
Figure above: Relief well and snubbing operation at time of blowout intersection illustrates the many tasks that must be coordinated through proper planning.
INTRODUCTION In view of stringent environmental and safety issues faced by today's operators, emergency contingency plans are no longer an optional, risk-management business decision. Today's managers who have the responsibility for responding to emergencies that affect the general public or the environment must either be prepared or face the consequences. The following discussion explains the basic blowout contingency plan document with respect to the following: • • • •
A BCP rationale Contingency planning goals Document structure Project life-cycle
BCP DOCUMENT SCOPE, CONTENT A BCP rationale. Hazardous waste, occupational health and safety, and air/water pollution and the effect on the environment are primary public issues. Most companies have emergency contingencies, but many are not prepared for rapidly responding to natural or man-made disasters. Unfortunately, several emergencies have occurred in recent years that have escalated into major crises, as perceived by the general public. Public inquiries into these crises, in some cases, indicated the companies at fault were not properly prepared in their response. Therefore, it follows that, through public and regulatory logic, the whole industry must not be prepared. And aftermaths of these inquiries typically result in new government regulations with increasingly complex laws and compliance issues that substantially increase costs, limit operational capabilities and may not be fully appropriate across the board. These laws affect the entire oil and gas industry, not just the companies involved, as the subsequent imposed emergency preparedness statutes evolve into an industry-wide problem. A viable emergency management program advertises a company's commitment to protect its workers, the general public and the environment. It meets compliance with federal, state and local regulations and it protects stockholders from liability and litigation. Failure to address these issues may have disastrous results. Contingency planning goals. The primary purpose of a BCP is to minimize danger to life, and protect the environment and valuable assets by minimizing response times and incorrect actions taken under stress. Obviously, in an emergency, the more details that have been worked out in advance, the more efficient the response will be. All blowouts and subsequent intervention techniques are inherently different. The range of situations can vary from a minor event in an easily accessible unpopulated land location, to a catastrophic worst case scenario near a populated area or a sensitive offshore location, with thousands of variations in between. This makes it impractical to cover all possibilities in a general contingency document. However, for rapid response, a structured organization and technical guidelines, with examples and trigger mechanisms, is essential.
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The key to efficient risk management, with respect to contingency planning, is being able to weigh risk vs. con sequence of the current preparedness plan against cost (insurance) of doing more. One objective of a BCP is to help a company determine an efficient level of preparedness. Document structure. A BCP should ideally be a subset of a general "All hazards" emergency response plan.6 The general plan would cover emergency management issues for a variety of typical hazards faced by an operating company, e.g., natural disasters (storms, tornadoes, floods, earthquakes); production/process failures (fires, explosions, spills/releases); society hazards (kidnapping, hostages, terrorism, war); transportation hazards; and blowouts. The purpose of making the BCP a subset of a general response plan is to establish a standard format for emergency management regardless of the hazard type. If the framework of the general plan is properly designed, it should fit a wide variety of operations and locations. This should simplify the emergency management portion of the BCP as a framework has already been adopted by the company for other emergencies. Fig. 6. Example emergency management organization to satisfy Phase 1 of the BCP's Part 1. Project "Life-cycle" concept. Every project has a life-cycle, i.e., the beginning and end of its evolutionary phases. A description of this cycle would describe those phases in a systematic fashion. Critical objectives are used to describe turning points in the process and mark transitions from one phase to the next. Thus, understanding the evolution of events necessary to complete a blowout control project is obviously a prerequisite to developing BCP objectives. Global objectives for a control operation may be generally described as follows: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12.
Emergency response activated Management team in place Blowout control team in place Blowout data analyzed Control options(s) chosen Necessary logistics initiated Blowout control plan complete Blowout control completed Well P&A'd or put in service Clean-up complete Legal implications settled Final reports completed.
The BCP must address each action required to achieve the example 12 life-cycle objectives. As development of the BCP is a project in itself, its life cycle must also be defined along with a method for periodic revision, audit and testing.
EXAMPLE BCP ORGANIZATION There is no best approach that should be universally utilized for developing a BCP. A non-mainstream approach taken by one company may be more appropriate for its organization and resources than trying to utilize a technique applied successfully by another firm. Each company must look inside its own house and evaluate its philosophy, organization and resources with respect to confronting a control operation in its operating area.
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The BCP organization presented here is a simple example based on the program of an international company with operating districts in diverse geographic and political areas around the world. It will require input from each local district to complete a plan that is customized to its particular internal resources, management structure and operating environment. The BCP Workbook. The required initial input noted above can be facilitated by a Workbook that acts as a guideline and bridging document for local management, for completing its specific BCP. It is recommended that this Work book be the vehicle which assures a consistent framework throughout the company and lets the local management team and responders provide plan input. Experience has shown that plans developed by one person or one group will not be used in an emergency. The Workbook document will be developed at a corporate level with assistance of management, safety and environment, engineering and operations personnel. An outside blowout advisor should be consulted, as well as any service company specialist who might be called to assist in a blowout emergency. It will guide a local operating district in developing Parts 1 through 5 of a custom BCP. And it will contain reasoning, suggestions and examples behind these actions, along with instructions for the local district on customizing the BCP for its area and keeping it up to date. Keep the Workbook separate to allow the actual emergency document to be brief and to the point. Five-part BCP organization. The completed BCP can be divided into five major parts, as described below and illustrated in Fig. 5, excluding the Workbook. This organization is based on functionality and actions required. Part 1-Blowout control management. This document will address organization, management and actions required to respond to an actual blowout emergency. This section will be relatively brief, stating only policy and actions required during intervention phases. This will include responding to the initial emergency through final blowout control, P&A, spill clean-up, and any legal insurance or other financial obligations resolved. Fig. 6 details the emergency management phase of Part 1. 2. Part 2-Pre-blowout contingency, risk. This document will address organization, management and actions required to perform "Pre blowout" risk and consequence assessment and procedures for various levels of specific contingency planning of existing fields, structures, individual wells, and planned future drilling pro grams. These specific plans will be based on a risk vs. consequence equation. This equation would justify additional expenditures for being better prepared than relying only on management and logistics procedures covered in Part 1. This section is also designed to be relatively brief, stating only policy and required actions. 3. Part 3-Contractors database. This document presents a database of critical contractors and services, which includes items such as. blowout control contractors, specialty equipment, materials, related service companies, consultants and software. It would be categorized and contain phone numbers, addresses, contact personnel, relevant services, brochures, special blowout control services (how they would fit into a local control project), company experience, alliances with other companies, and personnel CVs. Further, contract requirements and terms/conditions for working on a project in a particular part of the world should be included. 4. Part 4 -Technical library. Documents identified in this part address reference materials and procedures and would be voluminous compared to the other sections. This should include all inhouse and external approved procedures for blowout control operations, risk analysis, specific contingency planning, blowout control tools, blowout control materials, published papers, industry blowout database records, case histories, and other relevant material. References would be made from the other management and actions portions of the BCP to this section. 5. Part 5 - Company confidential files. This final document addresses confidential files such as pre-qualification ranking, evaluation discussion and call-off contracts with critical con tractors 1.
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and service companies. Blowout insurance policies, legal procedures and associated documentation requirements should also be included. Also, any other relevant items including emergency financing arrangements. Public relations, press, or legal documents and procedures of a confidential nature should be kept in this file. Table 2. Sample blowout control contingency plan, Parts 1 and 2 1.0 Introduction 1.1 Nondisclosure statement 1.2 Approval sheet 1.3 Distribution sheet 1.4 Preface 1.5 Executive summary 1.6 Table of contents 1.7 Amendments 1.8 Instruction on how to use the plan
2.6 Implementing procedures & actions 2.6.1 Actions at the blowout site 2.6.2 Actions at the office 2.6.3 Check lists
2.7 Blowout control planning, Phase 3 2.7.1 Blowout data acquisition requirements 2.7.2 Blowout severity classification 2.7.3 Strategy to evaluate blowout control options 2.7.4 Iterative design process 2.7.5 HAZOP study 2.7.6 Logistics review 2.7.7 Emergency facilities and equipment
2.0 Part 1-Blowout control management 2.1 Administration section 2.1.1 Purpose and objectives of Part 1 2.1.2 Company policy and strategy statements 2.1.3 Definitions and acronyms related to Part 1 2.1.4 Blowout control project phase descriptions 1 - High risk, potential blowout situation 2 - Blowout to task force in place 3 - Blowout control planning phase 4 - Blowout control execution phase 5 - Cleanup, P & A and/or remedial work 6 - Final legal and financial settlement
2.8 Blowout control execution, Phase 4 2.8.1 Plan implementation and project forecasts 2.8.2 Daily planning meetings 2.8.3 Safety and environmental protection 2.8.4 Regulatory agency involvement 2.8.5 Data collection and evaluation 2.8.6 Progress monitoring 2.8.7 Identifying milestones 2.8.8 Planning alternative actions 2.8.9 Judging completion-Is it over?
2.2 Management and response organization 2.2.1 Executive management 2.2.2 Support management 2.2.3 Emergency management organization 2.2.4 Blowout control task force 2.2.5 Blowout control crises team 2.2.6 Technical support organization 2.2.7 Operations and logistics support 2.2.8 Field control group (capping) 2.2.9 Field control group (relief well)
2.3 Organization project responsibility definitions
2.9 Post blowout control-Phase 5 & 6 2.9.1 Post blowout safety 2.9.2 P & A or remedial procedures 2.9.3 Clean-up 2.9.4 Legal and financial issues 2.9.5 Final reports 3.0 Part 2-Pre-blowout contingency plans 3.1 Field and well specific data archival 3.2 Risk assessment of existing producing fields and planned drilling activities
2.3.1 Contingency planning responsibilities 2.3.2 Actual blowout responsibilities
3.2.1 Identification of blowout possibilities 3.2.2 Estimate of probability of the event 3.2.3 Estimate of consequences of the event 3.2.4 Risk assessment of the event
2.4 Emergency communication 2.5 Blowout response level classification 2.5.1 Level 1-High risk operation, no blowout has
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occurred, but probability of escalation is high or consequences are high. 2.5.2 Level 2-Blowout has occurred, flowrates are low, complexity of control operation is low, there is little chance of escalation, there is no pollution and no danger to local public and total company exposure is low. 2.5.3 Level 3-A blowout has occurred and control complexity is high. Blowout rates are high, or there is a chance for escalation, or there is pollution, or there is danger to local population, or the total exposure to company is high.
3.3 Judging need for a specific contingency plan 3.4 Contingency plan evaluation 3.5 Establishing and maintaining emergency readiness 3.6 Training 3.7 Pre-qualification of critical contractors
A simplified BCP outline is shown in Table 2. The selected outline should coincide with a format consistent with your company's existing "All hazard" emergency management and response program. The basic objectives of the final plan should not change, however, from company to company. Note that the exact wording of this example follows the general subsections of Fig. 5, Parts 1 and 2 in context even though the terminology differs somewhat. The chart of Fig. 6 also corresponds generally to Part 1, Section 2.2.
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Blowout Control Technical Reference
Part 5 Hydraulics Modeling
Part 5
Hydraulics Modeling Matching known downhole well information with surface flow characteristics of a blowout via computer allows selection of the most efficient kill method
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Paul Smestad and Ole B. Rygg, Hydraulics Specialists, Well Flow Dynamics, Sandvika, Norway John W. Wright, Blowout Advisor, John Wright Co., Houston All well control design functions depend on construction of an accurate computer hydraulics model of the blowout at hand. Such a model incorporates all available downhole data on characteristics of the reservoir, well effluent, pressure, temperature etc., and factors influencing the surface flowpath of the blow. In turn, the hydraulics data allows development of a blowout model and, finally, a workable well kill model that will indicate the most efficient kill/control method to use.
BLOWOUT MODELING The first step in blowout control is to survey and assess the situation. For complicated blowouts, this may be difficult and a poor survey may result in mobilization of excess or incorrect equipment and other resources. On some projects, relief wells are started only after much time is spent on techniques that failed. A suspect contributor to such failures is lack of a good survey that prevents definition of an optimum control plan. Proper hydraulic modeling matches known downhole well data to a description of the flowpath, identifying possible interpretations and eliminating those that cannot exist. Need for further data collection will also be indicated. Usually, more data is available than is immediately obvious. Portable computers now can handle complicated simulators, besides being used for presentations and plots of collected data. Hydraulics evaluations thus can be produced and analyzed onsite. Even if data is limited, this exercise is useful since it can only improve understanding of the problem. For blowouts to surface, reasonable estimates of flowrate and type of liquid can be made by measuring size, height, width, color etc. of the fire. Exit conditions are indicated by direct observation of the wellhead area or via ROVs or minor excavation. Comparing well mechanical conditions with an estimate of formation productivity even allows simulation of wildcat blowouts. If more data can be gathered (pressure or temperature of flowing fluids, etc.) scenarios can be further narrowed. Steady state conditions exist for blowout simulations and vertical flow models used in production engineering may be used for modeling. For gas wells flowing high rates of condensate, oil wells with high GOR, or high water flows, it is important to use PVT and two-phase flow correlations. Models also must be able to handle changes in flowpath, flow regimes and friction correlations. Often, engineers familiar with the area where the blowout occurs can be used to manipulate the model. For complex projects, blowout specialists supplying special hydraulics models and simulators may be called on. Blowout modeling can provide surprisingly accurate results. In producing fields, good data may be available and kill operations can be planned with confidence. On underground blowouts, annulus and pipe pressures, temperatures, downhole flow measurements etc. may be obtainable. These parameters then can be matched in a simulation, improving the well kill operation. Blowout simulations provide a range of possible kill simulations and resource planning. Better definition of blowout rates also help in defining pollution containment needs and possible diverter design for sales or flaring.
KILL MODELING 35
The main questions to be answered by well kill modeling are: • •
Can the well be killed? What size equipment and capacities, and volumes of bulk material are needed?
These can then be evaluated in terms of: • • •
Logistics and mobilization times Cost efficiency of alternative methods Safety and risk analysis.
As a method is chosen and developed, detailed engineering can provide: • • • •
Pumping schedules (rate, time, power) Kill fluid types and volumes Pressure and temperature predictions Monitoring program.
Hydraulics kill simulations are applicable to all blowouts. To describe the modeling procedure, dynamic kill modeling as applied to a relief well kill, or top kill through tubing or snubbing pipe, will be discussed. Theoretical aspects of dynamic kills have been covered in writings by Blount and Soeiinahl, and others. They describe dynamic kill as a technique using flowing frictional pressure drop to supplement static pressure of the kill fluid being pumped up the annulus of the blowing well. Water is often used in dynamic kills and is a good choice as an initial kill fluid if reservoir pressure is not far above hydrostatic. Water also is well adapted for evaluating communication and kill effectiveness, or while waiting on mud supplies. Known proper ties make it easy to model and predict behavior of a kill operation. Dynamic kill principles are applicable to both heavy and lighter fluids. The modeling process can be split into two phases: 1. 2.
Establishing kill rates for different fluids, and maximum pressure and power requirements Defining an operational kill plan and schedule.
Establishing maximum rates, etc., can be done with steady state calculations. But dynamic (time based) calculations are needed to obtain kill volumes. Manually stepping a steady state simulator may also provide volumes. But they may not be accurate enough when required mud or specialty fluid volumes become large and logistics more critical. When fluid weights and rates are determined, and allowances made for losses, a dynamic kill can be simulated based on equipment limitations (maximum pump rate, pressure and power) and pressure monitoring. Often, it is necessary to also compute pressure downhole to prevent exceeding fracture pressure, tubular burst pressures, etc. Results can be presented as tables or plots showing flow and pump rates, pressures etc. vs. time or cumulative volume, as best suited for a particular kill. Fig. 9 shows pump rate and cumulative volume vs. time for an off-bottom intersection of a gas blowout with a relief well. Plots with different scenarios/options then can be used to monitor kill effectiveness and losses. Together with monitoring of BHP when possible, plots can also be used to pick the correct model when uncertainties exist.2
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Modeling results of blowout scenarios should be available as hard copies before the kill operation. Time seldom allows updating simulations during a kill, but comparing displays of collected data against models may be useful. All data such as pressures and rates should be collected on disk during kill operations for later analysis. At times more than one kill attempt may be needed due to uncertainties downhole and analysis of prior kill attempts may be required for success.
Fig. 9. Pump rate and cumulative volume pumped vs time for the dynamic kill of an off-bottom intersection of a gas blowout and relief well.
Fig. 10. Predicted vs actual pressures during a dynamic kill down tubing of an underground blowout from a high pressure/temperature reservoir flowing through the tubing and three casing strings.
MODEL REQUIREMENTS The model required for well control planning and operations will depend on circumstances and the stage of the operation. Often, hand calculations or solving empirical equations via spread sheets or similar calculation methods may be sufficient, especially if correlated with experience from similar situations. An overview of well pressures, flowing and static pressure gradients, and ratings of pipe and equipment may be all that is needed in the case of predictable operations such as cap ping production wells. Equipment, supplies, people, etc., available on site may be insufficient and mobilization of more resources may be necessary. The ability to quickly assemble a logistical plan is important. Hydraulics modeling will define equipment needs by setting upper and lower limits on kill rates, pressures and volumes. Often a well kill is described in terms of its main contributing element (dynamic kill, bullheading, volumetric kill, momentum kill, plugging, etc.). Calculations then can be made using a model or equations designed for the particular purpose. Results can be used to obtain densities, rates, pressures, volumes, etc. needed to regain static control of the well. For example, maximum pressure transients to be expected when shutting in a well at surface will be the fluid gradient back to reservoir pressure. A PVT calculation with reservoir inflow modeling provides an upper limit to the answer. Such calculations can be performed by a reservoir engineer familiar with the area using software in daily use. This can be improved by dynamic calculations of pressures using a reservoir model with wellbore storage considerations, superimposing whatever fluid is pumped into the well etc.
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Estimating an upper limit for the required rate for dynamic kill calculations can be made using published formulas or spreadsheet calculations for steady state flow, particularly if water is the kill fluid. As complexity or accuracy requirements increase, completeness of the modeling process becomes more critical. Modeling requirements also become more demanding when equipment and supplies will not fit in space available, as offshore, or if more pumps or more fluid are needed than available, or if pressure ratings at surface or down hole are exceeded temporarily. It may then be necessary to tune weight, viscosity, pumping pressure etc. against each other and against time, indicating a dedicated dynamic well kill model will be required. This model should include all physical processes included in the control operation, such as fluid properties, friction, flow characteristics, interaction with changes in reservoir inflow behavior, etc. Dynamic means time-based, so pressure, flow and pump rate characteristics can change vs. time. Importance of time-based models or simulators becomes obvious when considering, for example, buildup behavior when shutting in a well. For most reservoirs, BHP will be sharply drawn down during a blowout. And the initial buildup period can be used to pump kill fluid more efficiently than after pressure has increased. This effect will be the same in any kill operation. Similarly, physical processes involved (friction, momentum, weight, etc.) all contribute to the kill process, so that kill requirements will be lower if all effects are considered together rather than one at a time. Even the most sophisticated model will not work if input parameters are incorrect, or if the wrong options are chosen in actual calculations. Experience in such work is required, as well as a good quality control system including verification by engineers from several disciplines. All models have limitations because experimental data may not exist to verify them for extreme conditions. Examples of modeling discrepancies are pressure losses for high rates through tubulars of non-Newtonian fluids such as muds. Models exist for these conditions, but they may not be applicable over the range found in well kill operations. Published equations taken out of context can end up being used outside of their applicable range if proper care is not exercised.
INPUTS AND DATA ACQUISITION Fig. 11. Flowpath scenario in blowout was derived from production logging after a long, unsuccessful snubbing job. Relief well kill requirements were determined based on dynamic kill modeling and good match was made between predicted, actual kill rate used. Traditional use of well hydraulic modeling is in the area of production well design and optimization, where accurate reservoir, fluid, pressure, temperature and flow characteristics are available. One might assume that modeling is difficult for a wildcat blowout, where minimal data is available. But even limited data may provide enough information to start defining equipment requirements. Useful pressure and temperature data in this context can be obtained if access to the wellhead is available. Then, blowout flowpath and rates can be determined. For example, fluid flowing up tubing or drill pipe in a blowing well will have a different temperature from fluid flowing up the annulus for a given surface rate and pressure. If fluid composition can be determined, an accurate analysis can be made, especially for light fluids.
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Reservoir pressure is an important parameter in these calculations, especially in wildcat blowouts. However, mudlog data can be used to analyze inflow behavior, pressure, depth and type of fluid. Kicks that develop into blowouts often occur when work is focused on other operations such as workovers, etc. A pressure buildup that has gone unnoticed for some time may be reported as instantaneous, even though pit level, circulation rate and pressure data show it occurred over several minutes or hours. That results in a different inflow evaluation with corresponding decreases in required kill rates. Pressure, temperature and other production logging techniques provide data useful for modeling underground blowouts.3 Fig. 11 shows a flow path scenario derived from production logging after a prolonged snubbing effort, and mechanical data. Coupled with dynamic kill modeling, relief well kill requirements were determined and a good match was made between predicted and actual kill rates.
USE IN WELL PLANNING Two categories of blowout contingency plans require hydraulic analysis: 1. 2.
Well design, especially with respect to casing programs Contingency planning for blowout control.
Basic well design is adequately covered in the literature. Special applications may require kick analysis and evaluation of killing an under ground flow from the rig.3 This assessment is becoming more critical as operators try to cut costs by eliminating a casing string. Blowout contingency planning is needed for critical wells and structures such as offshore platforms to check on feasibility of killing wells and resources needed, especially for remote areas. Well design may also be affected when drilling program changes reduce risk of a kick developing into a blowout. Post analysis of kick handling is important to see if transient dynamic pressures or forces temporarily exceeded pipe pressure ratings or shoe strengths, in spite of static calculations indicating system integrity. This analysis can also help in determining if data used in the initial analysis was correctly interpreted.
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Blowout Control Technical Reference
Part 6 Underground blowouts
Part 6
Underground blowouts Underground blowouts between subsurface intervals are common and can result in a significant escalation threat if not recognized quickly and controlled correctly
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Brian A. Tarr, Mobil E&P Services, Inc., Dallas L. Flak, former Wright, Boots & Coots employee This article provides basic information on (1) how to recognize an underground blowout and (2) methods that can be used to regain well control.
INTRODUCTION Underground blowouts involve a significant downhole flow of formation fluids from a zone of higher pressure (the flowing zone) to one of lower pressure (the charged zone or loss zone.) They are the most common of all well control problems. This phenomenon differs from crossflow, which typically occurs within a long perforated interval and involves little or no reserves loss or escalation hazard. Underground blowouts can occur in drilling wells or producing wells, and are thought to be the most common in the latter because of tubulars corrosion in older completions. Unfortunately, no statistics on underground blowouts are available because most go unrecognized or unreported. What is known is that many surface blowouts begin as underground blowouts. And prompt, correct reaction to an indicated underground flow can prevent an even more serious and costly surface blowout. That leads to the observation that "experience is the best of schoolmasters, only the school fees are heavy."l
RECOGNITION Fig. 12 shows how an underground blowout may occur in a drilling well. But field personnel commonly fail to recognize the symptoms-most often, they are focused on curing presumed loss circulation. The following events indicate underground flow: An initial increase in drill pipe and casing pressure followed by a decrease. Typically, initial shut-in drill pipe pressure will drop to zero. Casing pressure may not change very much initially, but will steadily increase with time. • Gas, oil or saltwater will surface via drill pipe. Mud jetted out of drill pipe by the underground flow will be replaced with flowing zone fluids (no drillstring check valve). • Unable to get mud returns with blowout fluids at surface in annulus. Mud flows to loss zone with blowout fluids. • Able to strip up or down with no change in annulus pressure. Controlling pressure is fracture pressure or pore pressure at the loss zone. • Thermal anomalies are apparent on temperature log. Higher temperatures occur opposite shallower loss zone when flow is from bottom up. Lower temperatures occur opposite loss zone if flow is from top down. Spinner logs and other production logs may also provide indications. • No direct indication of pressure communication between drill pipe/tubing and annulus. • Lower than normal shut-in tubing and annulus pressures on a producing well. • Sudden change in GOR or WOR in a producing well with annulus pressure. • Christmas tree or BOP vibration of shut-in well. • Sudden tubing or drill pipe vibration and/or drag when pipe is lowered past point in the well where flow is occurring. •
CAUSES AND TYPES
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Most underground blowouts that occur while drilling result from lack of sufficient kick tolerance. Kick tolerance is the kick intensity (amount of underbalance) that can be shut-in without exceeding the fracture pressure of the weakest exposed formation after taking a given volume kick.2 Lost returns occur when kick tolerance is exceeded. But sometimes lost returns may occur before the kick is taken and an underground blowout will result. An example is drilling with excessive mud weight and surging the hole on a trip in. Resulting lost returns drop fracture pressure from breakdown pressure to a lower fracture extension pressure. This induces a kick that starts underground flow to the fractured zone. Another cause might be losing returns to a depleted reservoir with high pressure permeability exposed elsewhere in open hole. During drilling, casing holed by drill pipe wear or pipe defects can result in sudden lost circulation and an underground blowout. In producing wells, internal tubing corrosion or pipe defects can lead to failure and sudden imposition of tubing pressure on production casing. Defects or external corrosion of this outer casing can lead to either a subsurface or surface blowout depending on depth of the flowing zone. Gas flow after cementing is a major cause of surface annular blowouts. Less recognized is that annular bridging or top-out cement jobs can divert gas flow underground. Surveys of many multi-well gas fields indicate some underground flow likely occurred after cementing. Natural formation bridging and scale deposition shut off most of this flow. Many operators have been surprised when a temperature or noise log run in a shut-in well years after completion indicates crossflow. Generally, such flow is of little consequence. But there have been instances when this flow has led to surface broaching, fresh water aquifier contamination and shallow supercharging. Identification is difficult as temperature and noise logs must be run in a stable shut-in wellbore.
SIGNIFICANCE Besides losing reserves to charged zones and possible environmental impacts (fresh water aquifer contamination, shallow supercharging), there have been cases when gas or water have flowed into partially depleted oil reservoirs. In one instance, a deep H2S gas reservoir in Iran flowed for over a year into a shallow sweet oil reservoir. Six nearby oil wells began producing nearly 100% H2S, which was flared to limit expansion of the gas migration front until flow could be stopped by a deep relief well. Gas migration into a zone can be mapped using modern seismic techniques. This can assist greatly in locating a relief well or determining if flow is continuing after the well bridges or kill operations have blocked the surface flow path. Fig. 13 was constructed from seismic during a North Sea blowout. Note increasing migration of the gas with time. It should be pointed out that charging was occurring up dip from the wellbore. No gas is charging down dip of the wellbore. Many surface blowouts through drill pipe from high temperature-high pressure wells are caused when a deep underground flow at FBHP lowers the drill pipe mud column. The mud column will fall until it equalizes with FBHP and slowly be replaced by blowout fluids if mud pumps are shutdown. As drill pipe pressure drops due to this fluid exchange, the borehole can become unstable and collapse around the bottomhole assembly This "bridges off" the flow and allows FBHP to build back to SIBHP. Drill pipe hydrostatic which is equal to FBHP thus is subjected to the higher SIBHP. If the bit is below the annular bridge and no check valve is in the drillstring, drill pipe pressure will increase rapidly. Fluid hammer can occur when mud in the drill pipe is pushed rapidly to surface by formation fluid entering through the bit. A surface blowout then occurs if rig pump pop valves open and/or surface valving fails (cuts out or cannot be closed against the flow).
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This type of blowout will generally sustain if little surface solids production occurs. Fig. 14 shows flow discharge from a pop valve in just such a case. In this well, two kelly cocks and one standpipe gate valve were cut out by fluid hammer, leaks of gas and 17.9 ppg hematite oil mud. Surface broaching of an underground blowout can lead to loss of rig and severe environmental impact. As surface access is unavailable after surface broaching, flow must be controlled by a relief well.
CONTROL METHODS Fig. 15 shows a top kill flowchart that outlines steps to be taken if an underground blowout occurs while drilling. This flowchart was developed by Mobil E&P Services' drilling technology group based on Wessel and Tarr's paper.2 Initial steps are to mobilize on location cementing pump(s), additional mud storage, and cement batch mixer(s) if available. Mix and store at least one additional hole volume of mud on location. While mixing mud, bullhead water down the annulus to the loss zone to minimize annulus surface pressure and prevent subjecting casing, wellhead and BOPs to gas. This will assist temperature log interpretation by defining a temperature gradient at the loss zone. Consider running a calibrated rate gyro to provide better relief well targeting. Fracture extension pressure can be estimated by adding surface pumping pressure to water hydrostatic to the loss zone. The top kill attempt consists of the following steps: 1. Slow annulus pumping rate, continue annular water injection with cementing pump. 2. Pump water or mud down drillstring at 90% of maximum possible rate using rig pumps until pressure stabilizes. Record stabilized pressure and rate. Increase pump rate to maximum and record stabilized pressureand rate. 3. Stabilized drill pipe pressure is a function of the annulus two-phase (mud and gas or mud and oil) flow, hydrostatic and friction. If single-phase mud flow is attainable in the annulus, then the well is dynamically killed. Drill pipe pressure for single-phase flow can be accurately determined. If this pressure is achieved, the well is killed. 4. Lost circulation materials can be added to the mud to obtain a static kill after pumps are shut down. 5. If a dynamic kill with water or mud is not achieved, the recorded stabilized two-phase flow pressures developed during the attempted kill, in combination with results of the pressure/temperature log, can be accurately analyzed2,3 to determine what will be required.
ALTERNATE KILL METHODS If a top kill is impossible and normal hydrostatic control can't be restored, other procedures can be tried. A major complication to restoring normal circulation with a single weight uncontaminated fluid is possible supercharging. Supercharging can make it impossible to achieve a normal hydrostatic kill without first isolating the flowing zone from the charged zone. This procedure is used as the primary kill method when a dynamic kill attempt cannot be completed or converted to a normal static kill without re-start of flow by the supercharged zone. Isolation can be accomplished by bridging (natural or induced), plugging (lost circulation materials, soft plugs), blocking (gunk, sodium silicate, cement) or mechanical means (openhole packers, cased hole packers). 43
Natural bridging controls most underground blowouts because exposed shales cannot withstand resulting pressure differentials. Natural bridging can sometimes be induced to shut off underground flow by reducing FBHP via surface venting. FBHP can be high if flowing zone permeability is high and high wellbore fracture pressure limits FBHP- which can be sufficient to support exposed shales. Surface venting at a high rate can drop FBHP below fracture pressure and cause bridging. Plugging the flow path or the charged zone with lost circulation materials, barite plugs or diatomaceous earth squeezes is rarely effective in controlling significant underground flow, particularly if FBHP is equal to formation fracturing pressure. Tremendous quantities of drilling mud and lost circulation material have been pumped away in attempts to plug off a charged zone. Many times these are attempts to "regain circulation" when an underground blowout went unrecognized. Barite plugs are generally effective only if hydrostatic control is regained long enough to allow barite to settle. As with lost circulation material, use of barite plugs to control a severe underground blowout is generally a waste. Blocking the flow path with reactant plugs of fast-setting cement, gunk or sodium silicate reacted with cement or C aCl2 brine can be effective. Gunk was first developed by Goins as a means for squeezing off a lost circulation zone. 4 Gunk generally consists of 150 ppb bentonite and 150 ppb cement mixed in diesel oil and reacted with a fresh water drilling mud. The reaction is nearly instantaneous at a 2:1 to 1:1 gunk-to-mud ratio. The firm "breaddough-like" mixture of hydrated bentonite and cement can be easily drilled, but will handle high differential pressures given sufficient plug length. Alternately, 200 ppb guar gum and up to 100 ppb of fine lost circulation material can be used in diesel for a gunk plug that will react with saltwater flows, brines or salt muds. Guar gum can be replaced with modem high molecular weight polymers. Using these polymers with powdered CaCO3 as the lost circulation material produces a gunk that is 98%+ acid-soluble when reacted with brine. Invert gunk consists of 275 ppb of amine clay (amine-treated bentonite) mixed in water and reacted with an oil flow or oil mud. Mixing a water mud as a primary kill fluid that contains 50 ppb amine clay is useful in killing oil flows. The amine treated clay will react when mixed with oil and markedly increase viscosity of the water-based kill fluid. This provides greater annular friction and helps limit mud losses after the well is killed. Plugs of sodium silicate solution reacted with CaCl2 brine have also been used. Less recognized is that a mixture of 3:1 cement-to-sodium silicate will flash-set. Densified and highly retarded cement is generally used to obtain sufficient pumping time. Any of these reactant plugs requires: Two independent flow paths- drill pipe and annulus, for example -to allow subsurface mixing at the desired point. Snubbing or stripping operations may be required to get the two flow paths. In some extreme cases, direct intersection with a relief well may be required to get the second flow path. Mixing must occur near the flow zone and between the flowing and charged zone. • Cement batch mixers are used to mix and store unreacted gunk mixtures. Independent pumping systems are needed to prevent surface mixing. • All lines must be flushed and cleared to prevent surface reaction and line plugging. • Adequate diesel spacers (minimum 10 bbl) to isolate gunk. • Consideration of enviromental aspects in selecting gunk vs. sodium silicate. Gunk has been made and successfully applied using ester-based environmentally acceptable oil to replace diesel. •
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Reactant plug use to control severe underground blowouts should be done with the assistance of personnel experienced in their application. Misapplication can plug off the well above the underground flow and isolate the surface from the problem. This has generally been the case when cement was pumped without first controlling the flow. Mechanical isolation using packers snubbed in below a hole in tubing or casing and set to isolate the hole has been done. Open-hole packers have been snubbed in and set near the flowing zone. Modern open-hole packers are available to handle high differential pressures (7,000 to 9,000 psi) if annular clearance between packer and hole is limited. Coiled tubing has been used with these packers for control of underground flow in a few cases. A major difficulty is that once the packer is set and now is controlled, the situation is much like having a "bull by the horns" as hydrostatic control or bridging/plugging isolation is still needed
CONCLUSION Underground blowouts are a growing problem because of aging wells. Operators need to closely monitor existing producing wells for signs of problems. Most of the well control work done by author Flak last year involved producing wells-and tubulars corrosion was the single largest cause. Operators many times fail to respond immediately and correctly when an underground blowout occurs. That makes control more difficult as flow paths erode, downhole tubulars degrade (erosion added to corrosion) and supercharging occurs. In a drilling well, early recognition is a problem because indications of underground flow are masked by operations to restore circulation. The list of well conditions provided herein can be used to determine if an underground blowout exists. The flowchart provides step-by-step instructions for implementing a top kill to control the blowout. If a top kill is impossible, alternatives exist particularly if there are two independent flow paths to allow mixing of reactant plugs into the flow. This has been accomplished with coiled tubing, snubbing and directional relief wells. Mechanical plugs also have been used to isolate the flowing zone. Experienced personnel are required to simulate flow paths, make kill calculations and apply reactant plugs.
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Blowout Control Technical Reference
Part 7 Shallow Gas Blowouts
Part 7
Shallow Gas Blowouts After underground blowouts, shallow gas blowouts are the second most common type of blowout and the most common type of surface blowout. Loss of rig, platform and life have resulted from shallow gas blowouts. Invariably, the well is lost Michel Grepinet, Total Exploration Production Safety Division, Paris, L. Flak, former Wright, Boots & Coots employee. Little time and effort has been expended on shallow gas hazards, although industry has put a great deal of time and effort into analysis of kick control and blowout disaster mitigation,. Preparing for shallow gas 46
can save lives and rigs. This article examines the dangers of shallow gas, precautions and procedures for shallow gas drilling, and disaster mitigation.
DANGERS Two factors make shallow gas drilling a difficult challenge. First, unexpected pressure at the top of the gas bearing zone, due most often to the "gas effect" dictated by zone thickness and/or natural dip, can be significant. This pressure is usually unknown, seismic surveys being often unable to give an idea either about thickness or in-situ gas concentration. In more complex situations, deep gas may migrate upwards along faults. In Sumatra for instance, an influx could not be stopped even with 10.8 ppg mud at very shallow depth; the bit had crossed a fault plane. Second, low formation fracture gradients are a predominant factor in shallow gas operations. Reduced safety margins. These two factors result in reduced safety margin for the driller. Minor hydrostatic head loss (swabbing, incorrect hole filling, cement slurry without gas-blocking agent), any error in mud weight planning (gas effect not allowed for), or any uncontrolled rate of penetration, with subsequent annulus overloading, will systematically and quickly result in well bore unloading. Shallow gas flows are extremely fast developing events. There is a short transition time between influx detection and well unloading, resulting in much less time for driller reaction and less room for error. Poor quality and reliability of most kick-detection sensors worsens problems. Severe dynamic loads. Past history has disclosed the magnitude of severe dynamic loads applied to surface diverting equipment, and the high resulting failure probability. One of the associated effects is erosion, which adds high potential for fire and explosion from flow impingement on rig facilities. Rig cratering. The risk of cratering is a major threat for bottom supported units. As it is impossible to eliminate them (most shallow gas-prone areas are developed from bottom supported units) emphasis should be put on careful planning and tight monitoring during execution.
RIG SELECTION When selecting a rig, two facts should be kept in mind. First, major shallow gas fields (in particular in Indonesia) have been explored, appraised and developed from bottom supported units. Second, the most conspicuous disasters due to controlled shallow gas blowouts have involved drillships and semi-submersibles . Two support types are particularly exposed and should be avoided: mat supported jackups and drillships. These rigs are not designed to ensure proper stability and/or to withstand heavy loads imposed by a boiling gas plume. They are, therefore, prone to take on water, catch fire, lose stability and eventually capsize.
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Whatever the facility offered by semi-submersibles to move off location in case of uncontrolled gas flow, the questionable condition of the rig's mooring and release hardware, and the general unreliability of most semi-submersible surface diverting equipment, requires careful consideration. Rig selection for shallow gas areas should take into account: Selection of a "safe" drilling location, according to seismic survey mapping Design of an engineered drilling program, with priority given to permanent hydrostatic control of the well Comprehensive assessment of pre selected rigs, with final rig selection based on past experience and competence in shallow gas drilling, and also on diverting equipment fitness for purpose, layout, and structural ability to withstand a gas blowout long enough to permit a safe evacuation. Fig. 16. Model FSP bag diverter system provides automatic venting when piston closes packing. Fig. 17. Flow Selector, left, directs flow from FSP Diverter to one of two opposed vent lines for down-wind line selection.
DIVERTER SYSTEMS It is worth considering positive safety improvements which can be expected from more rational use of field proven diverter equipment. Traditional diverters. In the past, traditional diverters have failed due to shearing of insert-packer-element latching dogs caused by high thrust loads. Catastrophic loss of the Petromar 5 rig in the South China Sea resulted from this type of failure. Bag diverters. By nippling up a field proven sealing element, e.g., standard spherical type bag preventer, with a properly sized diverter spool just above the conductor pipe, the following could be achieved: Higher structural closing and diverting capacity, able to support heavy dynamic loads. Closing time should, nevertheless, be reduced, as it would be excessive in shallow gas. All prone-to-leak telescoping joints, required to adjust flowline slope, would not be exposed below the sealing element. • Properly sized, supported, secured and absolutely straight vent lines makeup. • Newly developed, integral closing and diverting systems could be used, Fig. 16. In this equipment, an integral piston below the annular packing unit rises to open the vent line as the packing unit closes. This has the obvious benefit of the absence of valving, and control system simplification. Maintenance is simplified, and chances of equipment failure, plugging and deficiency are drastically reduced. The use of a flow selector provides a method of directing flow to a downwind line, Fig. 17. • • •
This approach is commonly implemented by Total on North Sea platforms and in other areas, e.g., Indonesia, Thai land, Burmah, onshore and offshore, where there is shallow gas risk.
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Subsea diverters. Most floating drilling units have diverting and venting equipment which cannot be easily and efficiently modified. Many oil companies and contractors have by-passed these systems and changed procedures; reliance is put on quick move-off in case of gas influx. If the first point is debatable, the second one is questionable; mooring and release systems are not absolutely reliable. A recent case history disclosed the low level of operator confidence in the move-off option when, with a huge gas plume adjacent to a semi-submersible, an airborne evacuation was preferred. The best floater, shallow-gas blowout protection is subsea diversion. Total and Sedco Forex, and a few others, have selected this option for exploration and appraisal drilling activities offshore Kalimantan (Indonesia). Although thrust loads, erosion, fire and explosion cease to be applied to surface equipment, care should, nevertheless, be given to closing speed of the subsea bag preventer and shear ram, and to riser (or wellhead) connector release time. In addition, attention should still be paid to rig ESD systems, to the mooring lines release system, to firefighting and sprinkling capabilities, to location of the various remote controls, to avail able means allowing communications in a highly noisy environment, etc.
PROCEDURES The following is a summary of the recommended approach, used and progressively improved during more than 20 years drilling in shallow gas prone areas. Prior shallow seismic surveying. This is probably the only discipline which continues to progress and has the industry's unanimous support. Depending on field specifics, in particular, water depth and ease of access to the location, different techniques may be used, including HR surveys or 2-D and 3-D seismic surveys with specific reprocessing for shallow structures. Common procedure is to position the rig outside the mapped hazardous area, which may entail directional drilling to reach the initial target. Pre selection of one or more gas-free locations is also recommended for relief well drilling should the need arise. Shallow gas drilling requires, more than any other drilling or well servicing activity, comprehensive training for drilling personnel Pilot hole drilling. This option is often considered, but for different reasons. The first is the need for logging to calibrate seismic survey information. This is often difficult, as soft, shallow formations tend to slough, making successive control trips and logging hazardous. The second reason claims that dynamic killing in a pilot hole might successfully stop a shallow gas blowout; this reasoning is now widely questioned. While it is difficult to kick a shallow gas sand from the effect of drilled gas only, drilled gas can be a serious problem with uncased shallower sands above the gas sand being drilled. Finally, the only benefit of a pilot hole is in limiting total volume of gas-filled porosity to be drilled. Limiting penetration rate in normal hole sizes may be just as viable an option. Hydrostatic control. The permanent maintenance of hydrostatic control of the well is a must in any drilling situation. Selection of proper mud weight according to the gas effect assessment is essential. Failure to do so has caused major blowouts and capsizes. In addition, to maintain hydrostatic control, the following must be considered: • •
Avoidance of swabbing and hole imbalance Avoidance of losses (controlled ROP, solids control, deeper conductor pipe shoe, etc.)
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• •
Avoidance of gas influx during cement setting Limitation of penetration rate in gas-filled porosity.
Careful planning will help minimize risk of an uncontrolled gas flow. How ever, there have been cases where little could be done to prevent it, e.g., in Malaysia and India, with highly tilted layers, or in Indonesia with deep gas migrating along faults. On floating equipment, heavy mud can be pumped with returns lost to the seabed in riserless mode, or a lighter mud (designed according to the "gas effect" concept) may be pumped with the riser in place. The most important thing to remember is that the well will inevitably blowout, should seawater only be used to drill riserless shallow gas-bearing formations.
TRAINING Shallow gas drilling requires, more than any other drilling or well servicing activity, comprehensive training for drilling personnel. Rig personnel should be taught about: • • • • • • •
The origin of shallow gas The gas effect concept and the con sequence of haphazard mud weight selection The irrelevance of standard well control procedures The realistic procedures needed to face a fast-development event The necessary care and maintenance of diverting and emergency equipment Possible improvements which may help to reduce failure hazards Real case histories.
ENSPM-F1 (Pau, France) has launched, with the assistance of Total, a two hour "Shallow Gas Preparedness" training session.
DISASTER MITIGATION Two tools should be provided to drilling personnel to help prevent disaster escalation. First, the operator should design, with the drilling contractor, a common and realistic emergency procedure. It should be remembered that "emergency" status follows very closely the influx detection. Most procedures do not contemplate shallow gas, and pre spud meetings are usually so short dated prior to start-up date that con tractor personnel have virtually no time to properly "digest" procedures or specific risks. Second, as many drills as are necessary should be authorized and carried out to ensure that emergency procedures are known, understood, well implemented, and that emergency equipment is working and reliable. Realism should prevail in emergency drills and procedures. Case histories have disclosed that, once the well has been unloaded, there is virtually no chance to recover control until it collapses by itself or depletes.
OPTIONS Depending on the type of available diverting equipment, two basic options are recommended: 1. With unreliable equipment onsite (which should mean that, at the very outset, shallow gas was not expected and/or that proper equipment has been overlooked) no chances should be taken; the site should be abandoned immediately. 2. Alternately, should suitable equipment be available onsite, an attempt to kill the well may be initiated with some chance of success, provided that: o Detection has been almost immediate (rely on the flow detector) o The crew is speedy and orderly 50
The well is quickly diverted but not yet unloaded. There is, in particular, no time for multiple instructions to the driller, requesting countless phone calls, inopportune flow checks, or a time consuming rush to modify suction valving. o o
Regarding support type, instructions should acknowledge the respective and inherent weaknesses of the following: 1. For a bottom supported unit, with the possibility to improve design and load-bearing capacity of equipment, a well killing attempt may be contemplated under conditions defined above, provided that a nearly immediate swap to heavy kill mud is feasible. This type of old-fashioned, dynamic kill (heavy mud pumped as fast as possible, as soon as possible) has been successfully implemented during the past year. Unfortunately, rarely has there been a successful application of this method before the well cut out the diverter system, bridged or burned. 2. With a floating unit, assuming a subsea diverter is used and the influx detected soon enough, a well kill attempt may be contemplated as above. Should the riser be in use and locked to the wellhead with a pin-connector only, no kill should be attempted; immediate riser disconnection should be triggered and rig move-off initiated. If the influx is actually confirmed, move-off can be carried out. 3. Finally, with sufficient under standing of local fracture mechanics, it may be safer to shut-in some shallow gas kicks than to let them blowout through poorly designed diverting systems. In one instance, a blowout loss of $200 million was experienced when a shallow gas kick was diverted, resulting in fire and extensive platform damage. If the flow had been initially shut-in, the estimated surface pressure on conductor casing at the time the flow was first discovered would have been less than 100 psi. The best of all worlds would likely include a sound diverter system above a conventional pipe ram and choke line. This would allow initial well shut in and conventional circulation, if the kick were detected early. If the well were to broach, or the kick were not detected quickly, it could be reliably diverted. This is a controversial issue that is now under study by one major oil company after experiencing several large losses from diverted shallow gas blowouts.
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Blowout Control Technical Reference
Part 8 HPHT Case History
Part 8
HPHT Case History Control of an offshore HPHT underground blowout. Lessons were learned as to limitations of dynamic kills and novel use of gunk squeezes with a 1 1/4-in. snubbing string to accomplish control Dick Gloger, Drilling Manager, CNG Producing Co., L. Flak, former Wright, Boots & Coots employee.
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A fourth gunk squeeze was successful in sealing off annuli behind 2Y8-in. tubing located in CNG Producing Co.'s South Timbalier 76 Well F-1. This allowed bullheading gas back into the Big A sands with 18.5-ppg mud and killing the under ground blowout on Feb. 14, 1993. A 20-bbl cement plug was placed below 15,800 ft to permanently isolate A sands from the hole in the 2-7/8 in. at 14,829 ft. A pressuretemperature log run on Feb. 19, 1993, confirmed that there was no longer any flow in the wellbore. The following case history outlines steps taken to kill this high-pressure, high-temperature (HPHT) well's underground blowout.
WELL HISTORY Well F-1 is a vertical well located on a single tripod jacket in 66-ft water. The well was first put on production from the A-4 sand in January 1990. The A-1 was perforated and commingled with the A-4 in May 1991. On Aug. 20, 1992, the well was shut in for Hurricane Andrew. Prior to this shutdown, the well was producing from Big A-1 (17,536 to 17,566 ft) and Big A-4 (18,515 to 18,560 ft) perforations, with the bulk of the production from Big A-1. Prior to the shut-in, the well was producing 15 MMcfgd, 1,108 bopd and 13 bwpd, at 8,550 psi FTP. The last shut-in pressure prior to the shut-in was 11,300 psi. Annuli pressures just prior to shut-in were: 7%-in., 3,300 psi; 11-7/8-in., 4,500 psi; 16-in., 0 psi. After Hurricane Andrew, the 7-5/8 in. annulus pressure had increased to 6,200 psi; the well remained shut in because of damage to the local pipeline network. On Nov. 4, 1992, excessive pressure of 10,400 psi was discovered on the 11/s-in. casing during a daily well check. The 2-7/8 in. tubing and 7-in. production casing had ruptured below a packer set at 9,500 ft some time prior to this pressure development. On Nov. 16 and 17, attempts were made to pump into the 11/8-in. without success. On Nov. 19, a combination noise, pressure and temperature log was run to 17,657 ft. Underground flow to 4,600 ft was discovered, with flow exiting the 2-7/8 in. at 14,289 ft. On Nov. 23, 1992, a spinner log measured a sudden increase in well flow, with a concurrent decrease in flowing BHP. This indicated a deteriorating well condition. On Dec. 30, 1992, additional production logs were run to map the underground flow path and conditions, as in Fig. 18. On Jan. 9, 1993, the Odeco Ocean Columbia was moved on location, and blowout control operations began. Early temperature, TDT logs. The first temperature log of Dec. 18, 1992, gave indication of the underground flow path and conditions, Fig. 19. A sharp gradient located at 4,550 to 4,650 ft was the single entry point for flow escaping out 2Y-in. tubing at 14,289 ft. Conditions at 14,500 ft were 13,625 psi at 288 deg. F; temperature at 4,600 ft was 190 deg. F. A change in temperature gradient occurred at 10,810 ft, the suspected exit point for gas out the 7-5/8 in. and possibly the 11-7/8 in. There was a second slope change at 7,850 ft; this was believed to be the exit point for gas out the 11-3/4 in. casing and/or a temperature effect from top of cement. Flow then continued up the 11-3/4 X 14-3/4-in. open-hole annulus to the shallowest exposed massive sand located directly below 16-in. casing set at 4,469 ft. High flowing BHP at the 2-7/8 in. hole indicated a very restricted flow path.
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Fig. 19. Temperature logs, Dec. 18, 30,1992. The second temperature log of Dec. 30, 1992, indicated changes in flow path and less flow restriction, Fig. 19. This was indicated by a sharp temperature slope break at 12,200 ft, indicating a sand at this depth was then a major entry point for blowout fluids. Less flow was moving up to 4,600 ft, as indicated by the lower, 183 deg. F temperature. The well was blowing out at a higher rate, indicated by changed conditions at 14,500 ft. Pressure had dropped to 10,380 psi and temperature had increased to 301 deg. F. TDT logs confirmed gas entry into sands at 4,600 and 12,200 ft. The production logs were used to estimate flowrate and flow path pressure restrictions using methods outlined by Slungaard and Smestad.
DYNAMIC KILL PLAN, ATTEMPTS Well Flow Dynamics AS two-phase dynamic pressure drop software (see Part 5, April 1994) was used to model the blowout, with inputs from the last log run, Figs. 20 and 21. It was determined that it was possible to dynamically kill the flow with 18.5-ppg mud at a rate of 6 to 7 bpm at 12,500-psi maximum surface pressure on the 2-7/8 in. A major concern was possible high sustained mud losses after a kill was achieved. A plan was prepared and reviewed. A dynamic kill incorporates annular friction as the "choke" in the kill (2) As long as this friction is present, sufficient BHP is developed to kill the well. The major problem with a dynamic kill is the transition to a static kill if the well will not support static kill-weight fluids. This problem was suspected as the major limitation of this kill method to this well. But the method was evaluated as the lowest-risk kill option, with the continued loss after kill problem as the main handicap. Operation set up. Halliburton Special services rigged up to pump 18.5-ppg mud at 12,500 psi at 7 bpm on the Ocean Columbia pipe deck. Connections were made to allow pump in or bleed-off into tubing and all annuli. Digital pressure taps, as well as redundant flow meters, were placed on all annuli and tubing. Remotely actuated valves were used to facilitate reaction. Kill mud was mixed onshore and moved offshore. Supply boats were equipped with high-pressure, positive-displacement pumps to speed mud transfer. During the dynamic kill attempt, some required mud volume would be stored on these supply boats. Getting reliable charging of 18.5-ppg mud into Halliburton's suction manifold was the most difficult challenge, as centrifugal pumps do not handle this high-density, viscous mud well. Additional high volume centrifugal pumps were used. Kill success and loss. The well was successfully killed using 18.5-ppg mud at 6 to 7 bpm, as predicted by the OLGA WELL-KILL model, Figs. 20 and 21. Unfortunately, sustained losses seen after the kill were in the 1.5 to 2-bpm range. Sustained pumping after the kill did indicate that some "mudding off" was occurring, as injection pressure was slowly increasing over time. After many hours of pumping, to maintain the kill, it was decided to attempt to help seal annular losses with a combination of lost circulation materials and Diasel M (high solids high fluid loss pill). The well was still requiring >1.5 bpm to maintain kill hydrostatic pressure. A 50-bbl batch of Diasel M neat pill at 18.5 ppg and 50 bbl of Diasel M with Mud Check and Kwick Seal pill at 18.5 ppg were mixed. The neat pill of Diasel M was pumped and displaced into the annulus, followed by the LCM pill. A suction hose parted while pumping the second pill. Viscosity hold-up then allowed the 18.5 mud to U-tube away from the pill and allow hydrostatic loss. The well began to flow again and the
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dynamic kill was lost. As suspected, high sustained mud losses made it very difficult to transition to a static kill.
Fig. 20. Dynamic kill of underground flow with 1 8.5-ppg mud and 1 2,500-psi limitation, through 27/8 in. tubing. Base-case simulation scenario KM6DNY vs. Halliburton recorded pressures.
Fig. 21. Dynamic kill of underground flow with 18.5-ppg mud and 6 bpm limitation, through 2-7/8 in. tubing. Base case simulation scenario KM6DNY vs. Halliburton recorded pump rates.
INITIAL GUNK SQUEEZES Based on the difficulty of getting a static kill, a decision was made to attempt to seal off the annulus behind the 2-7/8-in. with gunk (300-ppb bentonite in diesel oil).3 This option was not first considered, as risk of squeezing off the flow channel to 4,600-ft sands and leaving a flow channel to 12,200-ft sands could complicate killing the well. Procedure, first attempt. The key to using gunk is to totally segregate it from any source of water until the plugging reaction is desired. All pumps, manifolds and lines were washed with diesel. A 100-bbl cement batch mixer was used to mix and store the gunk. Squeezes were started with 90 bbl of gunk in the batch mixer. The 1 4 X 2-in. annulus was displaced to fresh water. Led by 10 bbl of diesel, gunk was pumped down the 1l/4-in. Initially, gunk was pumped at 1 bpm, with > 0.2 bpm water rate down the annulus. At a ratio of 2 parts gunk to 1 part water, the annulus squeezed off. A total 58.2 bbl gunk was mixed with 31 bbl water into the annulus when it squeezed-off. Prior to the squeeze, shut-in annulus pressure at 0.5 bpm was 4,500 psi, and at 0.5 bpm, annulus pressure was 4,800 psi. Final obtained squeeze pressure was 8,300 psi over a column of fresh water at 0.5 bpm. This exceeded A-1 sand BHP at 17,536. Gunk pumping was shut down and water pumping continued, to displace gas out of the well to the A-1 sand. This initial squeeze broke down during this displacement. A second squeeze was attempted with the remaining 20 bbl of gunk. Second and third attempts. Pumping was shut down and a static annulus surface pressure of 5,200 psi was recorded. The second squeeze was started at 1:1 gunk-to-water ratio. Squeeze pressure trend indicated a different flow path was being squeezed in the second attempt; e.g., the many pressure break-backs indicated that the squeeze was against open hole. Insufficient gunk volume remained to complete this squeeze. Final static annulus pressure was 5,400 psi, and flowing BHP at 14,828 ft was 11,823 psi. 55
Initial annulus pressure was 6,100 psi at 0.5 bpm prior to starting the third squeeze. No increase in annulus pressure was seen until 15.3 bbl of gunk was displaced into the hole. Initial mix ratio was 4:1 (gunk to water). Four break backs were seen before the annulus squeezed off; final mix ratio was 1:1. A total 52.5 bbl of gunk was squeezed away with 29.4 bbl of water to get the final annulus squeeze pressure of 8,100 psi over fresh water. Static squeeze pressure of 8,000 psi over fresh water was seen. This was equal to 14,423 psi at 14,828 ft, or > 15,000 psi at A-1 sand depth. This exceeded static reservoir pressure of the A-1 sand and ended underground flow. On trip-out after the third squeeze, a gas bubble swabbed in and was trapped in the 2-7/8 in. Gas migrated up the wellbore and caused well pressure to climb. Ultimately, this pressure climbed above the squeeze pressure obtained with the third squeeze. The squeeze broke down and surface annulus pressure dropped to 6,200 psi, leading to re-initiation of underground flow. Well appeared dead. Tubing was snubbed down into position at the 2Y-in. hole, and preparations were made to squeeze a fourth time using 17.5-ppg mud as the mix fluid with gunk. The annulus was displaced with 64 bbl of 17.5 mud. Pressures during this displacement indicated the squeeze had healed and mud was killing the flow. The fourth squeeze was not attempted as gunk would not have been pumped into the annulus behind the 2Y-in. During the trip out, gas was swabbed in, which migrated around the 1-1/4 in. and stuck it with gas hydrates at surface. Electric induction heating blankets were used to melt the gas hydrates and free the 1-1/4-in. The annulus was loaded with 80 bbl of 18.5-ppg mud at 1 bpm. Final surface annulus pressure was 321 psi, and the well appeared to be dead.
RE-INITIATION OF UNDERGROUND FLOW Two attempts were made to set mechanical plugs in the 2-7/8 in. below the hole at 14,828 ft. Swabbed-in gas and gas hydrates led to sticking a slimhole inflatable packer. Some time during trips to fish this tool and clean out the 2-7/8 in., the gunk squeeze broke down and flow re-started. A bridge plug was stuck in the hole at 14,828 ft by the renewed flow, further complicating well control operations. It is believed that swabbed-in gas and the soft squeeze characteristic of gunk led to this renewed flow. Flow was confirmed on Feb. 13,1993, by a third pressure temperature survey. A sharp temperature gradient was seen at 4,600 ft, as in the first survey. Temperature at 4,600 ft was 236 deg. F, vs. 190 deg. F on Dec. 19, and 183،F on Dec. 30. Flowing pressure at 14,500 ft was 10,730 psi, vs. 13,625 psi on Dec. 19, and 10,380 psi on Dec. 30. And temperature at 14,500 ft was 298، F, vs. 288 deg. F on Dec. 19, and 301 deg. F on Dec. 30. Interpretation of this data indicated that less flow was present, compared to December 30, i.e., higher pressure and lower temperature at 14,500 ft. No flow was going to 12,200 ft as seen in the log of Dec. 19, i.e., no slope break at 12,200 ft. All flow was going to 4,600 ft, as evidenced by higher temperature there. And the flow channel to 12,200 ft seen in the Dec. 30 log was squeezed off.
FINAL GUNK SQUEEZE Based on previous gunk squeezes and the dynamic kill attempt, these problems were identified: • • •
Limited annular plug strength Limited hydrostatic development in annulus Swabbed-in gas on trip out.
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To address these concerns, these plans were made: 1. Use a 200-ppb bentonite plus 150-ppb cement mixture in diesel for greater annular plug strength 2. Mix gunk with 18.5-ppg mud for a denser plug mixture for greater hydrostatic pressure development in annulus 3. Squeeze off A-1 perforations with cement to allow trip ping without swabbing in gas. Successful squeeze, cement plug. A 100-bbl batch of bentonite/cement/diesel was mixed; a gunk density of 11.2 ppg was obtained. The lost bridge plug was tagged at 14,828 ft, and the annulus was displaced with 18.5-ppg mud. Initial annulus pressure was 5,216 psi at 0.26 bpm over 18.5 mud. A total 90 bbl of gunk was pumped out the 1-1/4 in. and mixed with 18.5 mud. Final mix ratio was 1.7:1 gunk to mud, and final annulus pressure was 5,683 psi at 0.26 bpm. The 467-psi pressure increase indicated the annulus squeezed off and allowed bullheading gas back to the perforations with 18.5-ppg mud. The 1-1/4 in. was displaced out with 18.5 mud and the well was overdisplaced with 18.5 mud at 0.75 bpm down the 1-1/4 in., and 0.75 bpm down the 1-1/4 x 2-7/8 in. annulus. Excess gunk and diesel spacer were bullheaded to A-1 perforations. Pumping was shut down, and tubing and annulus pressure went to zero with the well standing full with 18.5-ppg mud. The well was dead. A 17.2-ppg cement plug was mixed and 20 bbl were pumped down the 1-1/4 in. and bullheaded to A-1 perforations. The plug was displaced to 15,800 ft; and the well was shut in and static for more than 30 hr while waiting on cement. The 1-1/4 in. was snubbed out with no well pressure and the hole taking the correct fill. Final pressure/temperature log. A fourth P/T log run was made on Feb. 19 to confirm cessation of all underground flow. The down log recorded a maximum of 197 deg. F at 4,600 ft at 17:15 hr on Feb. 19, vs. 236 deg. F on Feb. 13. The up log recorded a maximum 182 deg. F at 4,600 ft at 23:10 hr on Feb. 19. This 15 deg. drop in temperature in six hr, in combination with normal temperature gradient seen below 4,700 ft, confirmed that the well was dead. Above 4,500 ft, the well was cooler than normal because of circulation and the gas-filled 11-7/8 and 16-in. annuli. The well was completely static during logging; thick mud did not allow logging below 11,600 ft. On Feb. 20, 1-1/4 in. was snubbed into the hole to establish circulation, condition mud and allow placement of additional plugs.
RECOMMENDATIONS Digital pressure and rate CRT displays that Halliburton Special Services provided were of great help. CRT displays were the key to understanding downhole pressure trends during kill attempts. It was learned not to let any pressure change go unexplained, and to not pump any fluid without prior knowledge of its pressure drop characteristics. The 6-speed, Vann 35 rheometer at the rig was used to get accurate viscosity data on all fluids at elevated temperatures. Excellent pressure-drop programs were used at the well site with this viscosity data to accurately predict friction pressures. The use of gunk was key to successful control of this well. No other material has the same ability to set on the fly in a gas flow, and feature unlimited pumping time. Mixing gunk with water or mud with use of a slimhole 1-1/4 in. string to control high pressure underground flow had never been attempted before. Excellent mixing control was possible at the exit hole using this 1-1/4 in.; and squeeze pressure development was very controllable. The cement bentonite gunk appears to be the better plug material and the 18.5-ppg mud the best source of water for the hydration reaction. In retrospect, the successful and final squeeze procedure using
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cement-bentonite gunk mixed with 18.5 mud and capped with a cement plug may have been the best firstattempt method to kill this well.
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Blowout Control Technical Reference
Part 9 Firefighting
Part 9
Firefighting The mechanics of oil/gas fires, meltdown and secondary damage, water/chemical/explosive extinguishing methods and considerations for voluntary ignition Coots Matthews, Consultant, Boots & Coots L.P., L. Flak, former Wright, Boots & Coots, employee.
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This article deals with the highly visible and potentially dangerous operations of extinguishing and capping burning blowouts. To understand the nature of oil and gas fires in blowout conditions, basic mechanics and terms are explained, and important features of meltdown and radiant heat exposure limits are discussed. Methods of extinguishing fire with water, chemicals and explosives are described, and examples of cap ping a well while it is burning are given. Finally, reasons for voluntarily igniting a blowout in high risk wells are presented.
INTRODUCTION Surprisingly few surface blowouts ever ignite. Except in Kuwait, in 1991, less than 10 blow outs per year ever catch on fire, world wide. Typically, large formation water flows lifted by the hydrocarbon flow make ignition difficult if not impossible. Water cones into the blowout zone, drawn in by low flowing bottomhole pressure; or adjacent wet zones are exposed to the flow path. Highly flammable blowouts may never ignite if no ignition source is present and flow is quickly dispersed. Thus, knowledgeable and experienced blowout specialists always restrict blowout access and carefully inspect the area around blowouts for ignition sources, particularly areas within an explosive vapor cloud. Failure to do this on a recent inland barge blowout in South Louisiana resulted in two deaths and other severe injuries.(1) "Victory awaits those who have everything in order-people call that luck. Defeat awaits those who don't- this they call bad luck." Roald Amundsen (leader of the first expedition to reach the South Pole)(2)
OIL AND GAS FIRE MECHANICS Knowledge that hydrocarbons are highly flammable is common to our industry. Less well known are the explosive characteristics of hydrocarbon vapor-air mixtures and the dramatic impact of ignition of these mixtures on surrounding structures and personnel. To understand this risk, some ignition terms must be understood. Flashpoint is the lowest temperature at which a material gives off enough flammable vapor to produce a momentary flash when exposed to a small flame. The flash point of gasoline is -43 deg. C (-45 deg. F), which is the reason it is considered highly flammable. Spontaneous ignition temperature is the minimum temperature at which a material spontaneously ignites. Methane has a relatively high spontaneous ignition temperature of 537 deg. C (999 deg. F). This makes reignition of a methane fuel fire after extinguishment difficult. In practice, low-flash-point, low-spontaneousignition-temperature gas condensate blowouts present the greatest blowout ignition hazard. Explosive limit of differing blowout flows varies with chemical composition. There is a minimum ratio of hydrocarbon vapor to air, below which ignition will not occur. Alternately, there is also a maximum ratio of hydrocarbon vapor to air, at which ignition will not occur. These limits are termed the lower and upper explosive limits. For gasoline vapor, the explosive range is from 1.3 to 6.0% vapor to air. For methane, this range is 5 to 15%. "Crude oil is a highly volatile, explosive cocktail which is lighter than water and burns twice as hot as coal. " (3) Vapor cloud explosion is possible through the following sequence: • • • •
Hydrocarbons are released near wellhead Some gas liquids flash evaporate, forming an aerosol of liquid droplets and vapor Heavier hydrocarbon liquids that do not flash evaporate pool around well and release vapors Vapors mix with air and form a combustible vapor cloud 60
• •
An ignition source is exposed within this explosive mixture Combustion starts and a flame front propagates through the flammable zone.
Research has shown that speed of the flame front movement is directly proportional to the amount of blast over-pressure. High flame front speeds and resulting high blast over pressures are seen in situations where there is a significant amount of confinement and congestion that limits flame front expansion and increases flame turbulence. Most vapor cloud explosions are deflagrations, not detonations. Flame speed of a deflagration is subsonic, with flame speed increasing in restricted areas and decreasing in open areas. Significantly, a detonation is supersonic, and will proceed through almost all of the available flammable vapor at the detonation reaction rate. This creates far more severe peak over-pressures and much higher amounts of blast energy (4). Offshore rigs, production platforms and inland barges are at greatest risk. Hard-welded quarters and other enclosed areas are at particular risk as it is possible to get detonation in these confined areas.
MELTDOWN The pressure-feed fire of a blowout will totally destroy the surrounding steel structure in minutes. Derricks have fallen-in less than 30 minutes after blowout ignition. The core temperature of a low-GOR 28 deg. F API crude oil blowout in Kuwait was measured at 1,677 deg. C (3,051 deg. F). And a radiant heat temperature of 510 deg. C (950 deg. F) was measured at ground level, 15 m (49 ft) from the base of this large vertical fire, which was estimated at 30,000 bopd. Oil well firefighters commonly see surrounding sand and stones melted and fused on large fires. Steel loses most of its strength at 500 deg. C (932 deg. F) and melts at 1,500 deg. C (2,732 deg. F). Radiant heat. Common radiant heat exposure limits are: • • •
0.5 KW/m2: Maximum working level for unprotected personnel 10.0 KW/m2: Maximum working level with protective equipment 15.0 KW/m2: Maximum working level for equipment.
On a very large Kuwait fire (about 30,000 bopd) the following heat radiations were recorded (upwind): 1.5 KW/m2 at 200 m (656 ft); 10.0 KW/m2 at 75 m (246 ft); and 15 KW/m2 at 35 m (115 ft). To understand the significance of these radiation levels, aluminized reflective fire entry suits are generally rated to only about the 15 KW/m2 radiation level. Oil well fire fighters commonly work inside the 15 KW/m2 level using Nomex long johns and hoods, heavy socks, insulated boots and heavy cotton outer wear, under a continuous water spray. In Kuwait, maximum recording heat strips measured temperatures as high as 230،C (446،F) on the hard hats of firefighters. The one reason that they continue to use heavy aluminum hard hats is that common plastic oil field hard hats melt. Fig. 23. Air-transportable fire pumps stocked by oil well firefighters. Sufficient water application to a blowout greatly reduces heat impact on surrounding structures, Fig. 22. Radiant heat is effectively eliminated as a problem when sufficient water is pumped into the fire. Work in high heat radiation areas is obviously dangerous and should only be attempted by experienced oil well firefighters.
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Secondary damage. Flammable fluid storage and gas handling systems can start a fire that leads to well blowouts, e.g., Piper Alpha. At Piper Alpha, it was established that the night shift had attempted to restart a pump, unaware that a key pressure safety valve had been removed during maintenance. The low-lying cloud of condensate resulting from the leak ignited and caused an initial explosion followed by a large crude oil fire.5 In the resulting disaster, 167 men lost their lives, but the relatively small blowouts from fire-damaged well heads had nothing to do with their deaths. Fires from improperly handled production streams and stored flammable liquid can be a greater fire risk and cause more damage than a blowout. Emergency response plans must address how stored flammable fluids on an offshore platform are displaced with water and de-pressurized if a fire or well blowout occurs.
EXTINGUISHMENT METHODS Several methods are available to extinguish a blowout fire. Summarized here are the use of water, chemicals, explosives and an example of capping a well while it is burning. Fig. 24. Major rig fire water system designed for Kuwait Oil Co. Water. The most important method to limit fire damage to structures from a blowout fire is application of water. The common use of sprinkler heads and deluge nozzles in modern offshore production platforms has greatly reduced the risk of a Piper Alpha type tragedy. Yet, in land rig operations and older offshore moveable rigs and platforms, there is little or no water protection integral to the operation. Without modern fire water systems, blowout ignition is more likely, with probable total loss of rig or platform. Water alone has extinguished some of the largest blowout fires experienced by our industry, once flow was directed vertically by firefighters. Water works to extinguish blowout fires by various means: •
It cools fire below spontaneous ignition temperature by absorbing heat as it is flashed to
steam • •
Water flashed to steam displaces oxygen and smothers fire Powerful water streams displace fuel from fire.
Main water use in blowout fire fighting is not to extinguish the fire, but to allow men and equipment to work near the fire. Early firefighters' efforts on burning blowouts involve removal of debris and working to get the fire burning vertically. Wells capped while burning may require more water than conventional extinguish-and-cap efforts. Offshore marine vessels commonly have substantial firefighting capabilities, i.e., 10,000 gpm, with monitors mounted high on the vessel to allow water to reach even large plat forms. Fire pumps in inventory with oil well firefighters are smaller, air transportable systems, Fig. 23. These pumps provide 4,000 gpm at 250-psi head. Two of these pumps are used on a typical large fire on a land or inland barge rig. Oil well firefighters also inventory piping systems for these pumps that contain 4-in. aluminum water delivery pipe, fire monitors and associated equipment. One U pipe rack" is used typically with two pumps on a large onshore fire.
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Modern derrick barges, MSVs, pipeline lay barges and large hydraulic dredge barges have been used offshore to support firefighting efforts. On land, common mobile fire pumps in use with civilian fire departments have been used on small fires. These truck-mounted pumps can provide 1,500 to 3,000 gpm, but require greater care and may present associated problems in coordinating with civilian firefighters. Onshore water requirements depend greatly on the nature of the fire, but most blowouts would be adequately handled with the system out lined in Fig. 24. This system is similar to that used for all firefighters in Kuwait in 1991, and was designed by the authors for Kuwait Oil Co. in December 1990, prior to any Kuwaiti blowout. Note use of the fire trap between run-off and re-circulation pits to allow safe recovery of produced oil, and fire water recycling. Produced water can be added to Fire water systems to reduce external water supply needs. Multiple water wells can be used with trucked-in water if no near-surface water supply is available. Firefighters inventory high volume, low-head transfer pumps if water must be moved some distance from the f'ire. A water supply of about 9 bpm is adequate for most fires, given sufficient surface storage, 24-hr delivery and recycling. On critical wells near populated areas or other facilities, or in remote areas, emergency response plans should consider sourcing the water supply and whether a deluge system should he incorporated in drilling plans. Chemicals. Foam and dry chemicals have been used in limited roles in oil well firefighting. Foam consists of water, foam concentrate and air. It is used on liquid hydrocarbon fires to smother the fuel surface (excludes oxygen), suppress vapor emissions (explosive vapor release is restricted), generate steam (removes heat and displaces oxygen), cool surface (heat absorption) and reflect radiant heat. Use on blowouts is restricted to gas condensate fires and oil wells where lateral flow has led to a large fire-surface area. Foam can help contain fire near the source and allow work near the flow source. Generally, water alone is adequate for this, but with large, low velocity, lateral oil flow, foam may be required. Modern firefighting foam such as 3M Lightwater ATC is commonly used with the William's Hydro Foam nozzle. This selfproportioning nozzle, when used with the ATC foam, allows foam to be thrown farther. Nozzles are available to handle up to 6,000 gpm, but the 2,000-bpm nozzle is most used on oil well fires. Dry chemical extinguishers work like water, but principally act as a smothering agent. Common compounds used are sodium bicarbonate, Purple K (potassium bicarbonate base) and Monnex (highest efficiency rating). Use is generally on methane well fires where explosives cannot be used and water supply is inadequate. The main problem is that these systems are "one shot" devices that can not be topped up or refilled during application. The largest systems commonly available have 68 kg of powder in storage. In Kuwait, extremely large (1,350 kg) dry chemical extinguishers from Ansul were used with Purple K powder as part of a mobile firefighting system used on smaller fires. Also used for the first time in Kuwait was the new William's Hydro-Chem nozzle that allows one nozzle to be used for water, foam and dry chemical. This would allow 1) using one nozzle to start water cool down, 2) adding foam to knock out the liquid fire, and finally 3) injecting dry chemical to knock down the remaining gas fire. Use in blowout fire fighting will be limited, but this new nozzle has good potential in industrial applications. Explosives. Commonly available explosives such as 80% nitroglycerin grade dynamite are still used in oil well firefighting. It is believed that M. M. Kinley invented the presently used method, which was employed by experienced firefighters in the 1920s. For the mechanism, slow-speed photography indicates that the
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explosion acts to temporarily drive fuel away from the point where the flame develops and deprive that immediate area of oxygen to support instant reignition. Depending on fire size and prior experience, up to 500 lb of explosive may be used. Explosives are used today in con junction with water to cool the shot and prevent reignition, when water supply or pump capability is insufficient to extinguish fire alone. As in any firefighting effort, all ignition sources must be removed from the well area prior to making the shot. Typically, a smaller lube oil drum is used and packed with explosive. This drum is detonated using detonating cord run through the athey wagon boom. The cord is electrically detonated at the front of the athey wagon, some 60 to 70 ft away from the explosive drum. Heat insulating, silicon based cloth and water spray are used to protect the explosives from the fire. There is little risk of premature explosion as hot spots would only lead to non-detonation, and the explosives would burn up in the fire. This is, interestingly, the lowest cost fire fighting technique, as the cost of a shot may be less than $2,000. This is exceeded by one recharge of the large Ansul dry chemical extinguisher and just a few drums of ATC foam concentrate. Less-experienced firefighters tend to discount the use of explosive shots only because of their lack of knowledge in the method, not because of any legitimate safety or economic reason. Killing flow with well on fire. Recently, a blowout in inland waters was capped while burning by Boots & Coots to limit environmental dam age and for added safety. This technique has also been used on an H2S blowout in Canada after Boots & Coots replaced a company that lost two men during conventional capping attempts.6 The basic method involves using conventional capping stacks, as will be described next month, but equipping the capping BOPs with heat shielding and water deluge to limit high temperature exposure. Once the BOPs are over the flow and burning is underway above the riser tube, flow within the capping stack helps protect the BOPs. Wells have been stung, as will be discussed next month, while on fire to kill both flow and fire.
VOLUNTARY IGNITION H2S hazard has led operators to voluntarily ignite a blowout for safety. Fig. 25 is a spectacular picture of a 30% H2S blowout (>50 MMcfd) taken immediately after ignition by a flare gun. Interestingly, no more than 2 ppm SO2 could ever be detected at ground level in the plume from this fire. Most operators that are planning these types of high-risk wells have plans that leave blowout ignition choice up to the field personnel. Two reasons for considering voluntary ignition are discussed here. Pollution. This potential problem has not yet-to the authors' knowledge-led an operator to voluntarily ignite a blowout. However, after natural ignition, major efforts have been taken to keep the fire burning to lessen pollution. There is little question that a burning blowout presents less long-term environmental dam age than a well spewing oil unchecked into a marine estuary. And recent experiences have indicated that voluntary ignition of a rig, or particularly an inland barge, may be the less-expensive option, considering the cost of environmental dam age and clean-up. Operators have spent more money on clean-up than was spent on blowout control. Yet, ignition of an oil well blowout on a major offshore plat form would tremendously complicate control efforts and likely result in total platform loss. A small land rig or inland barge rig represents less capital investment and easier removal of fire damaged debris. Difficult legal and insurance questions must be answered before an operator can determine its policy.
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Safety. This consideration is a major concern in the blowout control business. Unexpected vapor cloud ignition resulted in the only deaths (two) and lost time injuries (six) seen by firefighters in Kuwait-all by inexperienced firefighting teams. With the recent deaths of two men in Louisiana and near misses seen over the years, consideration should be given to igniting some blowouts for safety. This is an easier choice if there is H2S present, significant pollution potential, or close proximity to civilian population. Blowout work is safer on burning wells. In many cases, operators and firefighters in hindsight wished that they had opted for voluntary ignition from the start, rather than suffer the consequences of an unexpected ignition. On critical wells of higher risk, operators should consider whether voluntary ignition should be part of the emergency response plan and, if so, instructions and flare guns should be made available to wellsite personnel. "We judge ourselves by our policies. Others judge us by our actions" Anon.
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Blowout Control Technical Reference
Part 10 Blowout surface intervention methods
Part 10
Blowout surface intervention methods Descriptions of debris removal techniques; special services like junk shots, hot tapping and freezing; and proven methods of well capping Martin J. Kelly, Jr., Partner, Boots & Coots, L. P., Houston and
L. Flak, former Wright, Boots & Coots employee
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This article reviews the physically demanding job of clearing away damaged wellheads, BOPs, rigs and platforms to allow surface control of a blowout. Basic special tools and techniques used in these efforts are explained. Capping equipment and installation steps are reviewed. Options of diverting blowouts and inducing bridging are noted. And snubbing on blowouts and the difficulties this presents are discussed. Figure above. This 1992 blowout in inland waters was capped while burning to limit pollution.
INTRODUCTION Experienced oilwell fire fighters bring more knowledge in the area of stopping leaks, removing dam aged equipment and controlling flow safely from a blowing well than in any other area. Many control options are available, as partially reviewed below. The key is selecting a control option that has the best chance of success, mini mum risk and viable economics. Time is also a major factor, as well conditions can change. The following discussion should be used as a basic guide to control options, methods and limitations. DEBRIS REMOVAL Fig. 27. This meltdown was the result of a voluntary well ignition of a deep H2S well blowout in Mississippi (see photo on page 106, World Oil, October 1994). The significant task of clearing away damaged rig or offshore platform components to expose the wellhead(s) is a first step on burning blowouts. Rig removal may also be required on non-ignited blowouts to allow removal/ replacement of defective BOPs or well heads. Only a few individuals have directed operations to remove destroyed rigs over burning blowouts. Even fewer have directed debris clearing operations on offshore burning blowouts. Offshore challenges. Offshore efforts are based on exposing the wellhead(s). This involves clearing away upper decks and possibly melted remains of the rig and substructure. In Fig. 26, operations in 1992 by Boots & Coots on a burning barge rig in open bay waters behind a barrier island can be seen. The barge key-way was first cleared of melted rig debris. A major effort to cool the drilling barge to prevent further thermal deterioration while pumping it out, to float the drilling barge off the well, is illustrated. Water spray is directed at the barge and not the fire to maximize oil combustion and limit pollution. Oil containment booms are set around the work area and pumped off barge fluid and skimmed oil are directed into storage barges. Well fires on massive offshore structures would require large semi-submersible-based derrick cranes to get sufficient deck height to match up elevation of the well bays. Derrick barges can be used on smaller structures. Major firefighting firms have crane hooks that work with large offshore cranes for debris clearing. Additional tools are generally custom fabricated at offshore sites using the extensive machine shop and welding/fabricating capabilities of the work vessels. Cutting/removal techniques. Cutting away massive steel debris on large land rigs or offshore structures is sometimes required. Large fires will progressively melt away obstructing steel and at least partially expose the wellhead. If clearing is required, it can be done by various means, as described here. Mechanically ripping, bending or fatiguing (repeated bending) away the debris with athey wagon and debris hook.
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Swab line used as a reciprocated cable between winches is used to cut away wellheads or tubulars in areas and applications where only small cuts are required and high pressure abrasive cutting equipment is unavailable. Recently, a blowout in Venezuela required cutting away 6%-in. casing, 2Y-in. tubing and a polished rod with swab line. The cut required 18 hr to complete. This cut could have been made in less than 2 hr with a high pressure abrasive jet, but this equipment was not available in Eastern Venezuela. Thermal lances or custom long cutting torches can be used to cut away debris on burning blowouts. In Fig. 28, Joe Carpenter with Boots & Coots can be seen preparing a long cutting torch which he used to cut away the kelly and rig floor beams under cover of water and reflective roofing tin on a 1992 blowout and fire. Very few individuals have the experience to do this safely. Explosive cutting with shaped charges can be done on massive beams or tubular sections obstructing blowing wellheads. Shaped charges can be made in the field using raw C4 plastic explosive in fabricated holders. Point cuts, linear cuts and circular cuts can be fabricated by fire fighting explosive experts. Manufactured cutting charges are stocked by explosive manufacturers in some regions, but cannot be custom con figured to the application. These are generally the same companies that make oilwell perforating charges. High pressure abrasive cutting with jet attachments that allow remotely operated cuts is the newest technology in firefighting. The technology was first successfully applied in the Kuwait fires. Halliburton markets this service to the oil field today. Smaller ultra-high pressure cutters are available out of industrial applications. Each system has particular applications and benefits. The principal benefit of the Halliburton system is the ability to mount the cutter on a boom for remotely applied cutting. Meltdowns of land rigs can usually be removed using athey wagons, debris hooks and large dozers. Typically, at least two D8N dozers with winches are used. In one case of a large land rig meltdown on a deep Mississippi H2S blowout in 1985, Fig. 27, one D9N dozer walking an athey wagon with a hook into the debris and five stationary D8N dozers with 1-1/8 in. cable spooled off Cat 57 winches tied into the debris were required to skid off a massive accumulation of melted steel contained between two main substructure rig beams. Debris clearing on burning wells is the most physically difficult firefighting operation and can take far longer than actual capping. Once debris is cleared and the well is exposed, final control operations can begin. The fire is generally not extinguished until the rig is cleared away. Firefighting operations were discussed in the previous article; as noted therein, the well may be capped while on-fire, based on pollution or H2S gas concerns.
SPECIAL SERVICES/OPERATIONS Fig. 28. Preparing for debris removal of fire-damaged equipment with a long cutting torch on a small Texas land rig. Specialized techniques have been designed by firefighters and service companies to achieve certain objectives such as plugging leaking connections, temporarily shutting off flow in lines, tapping into tubulars, cutting and stinging. Here are several examples.
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Junk shots are used to plug leaking valves, flanges or BOPs. If an injection line can be tied into the well below the leak, this control option is possible. Time is critical as leaks are seldom stable and will erode out the leak path. The method involves loading a pump-in line near the well with shredded rope, rubber, nut hull, ball sealers and even golf balls to plug the flow path and allow conventional well killing operations to proceed. Higher mechanical strength fibers (Kevlar) and steel-rein forced rubber have been used to seal a leaking kelly cock valve (SIDP of 6,800 psi) through a hot-tap-drilled 1-in. hole. Stinger use requires junk shots to effect a seal around the stinger. Freezing is used to place an ice plug within shut-in wells (within pipe, well heads or annulus) to allow removal, repair or replacement of wellhead equipment. Freezing has not been used to control a blowing well. Some inventors attempted to market devices using liquid nitrogen to freeze-off blowing wells in Kuwait, but simpler control methods were available. Difficulties were seen in maintaining a plug of frozen oil and brine while making extensive surface repairs to blown-up wellhead equipment. The method usually uses dry ice to freeze water or fresh water-bentonite slurries. Methanol can be used with dry ice to get a lower temperature. As a 75% methanol/water mixture has a freeze temperature of some -200 deg. F, methanol water mixtures could be potentially cooled by liquid nitrogen and the cold methanol/water mixture circulated around the area to be frozen. This would allow control of the applied temperature to the steel-problems with low-fracture toughness in super cooled steels have been seen in nitrogen pumping service when pump rates exceeded heater capabilities and liquid nitrogen was pumped into wells. Hot tapping and valve drilling equipment has been used on blowouts to allow pumping into wellheads, tubulars or fire-frozen valves. This equipment is available from most major fire fighting companies as part of their service capabilities. For a hot tap, a saddle clamp is installed around the tubular and a pack-off energized. Within a lubricator, a machine drill bit cuts through the tubular with pressure held slightly higher on the outside so positive indication that a hole has been made is seen. After the hole is cut, it can be reamed out to 1 in. Valve drilling machines are available to drill out frozen gates. Up to 3-in. holes have been drilled and larger hole sizes can be milled out. Pneumatic cold cutters and high pressure abrasive cutters are used to strip away outer casing strings to expose inner strings for well capping. ABB Vetco Gray offers equipment to make vertical stripping cuts to split casing strings. Light linear shaped charges can also be bent around tubulars to make cuts. Pneumatic cold cutters, commonly used in the pipeline business, are used most frequently. Stinging is a relatively rare control option that gained some fame in Kuwait, where 35% of the blowouts were con trolled using this method. The method involves snubbing a hollow conical device into the flow. A tee threaded above the device allows stinging the well with flow diverted vertically through the stinger and tee. The stinger is snubbed down into the blowout opening and the vertical flow path is shut off with a valve. Annular leaks between stinger and its rough fit to the blowout opening are sealed with junk shots to allow bullheading kill fluid into the well.
CONVENTIONAL WELL CAPPING New wellhead installation can be required if existing wellhead equipment is destroyed by the blowout. After exposing inner casing, a new wellhead (internal O-ring seal and external weld-on) is snubbed down over the inner pipe string and welded to the outer pipe string. An example would consist of a well with 13-3/8-in. surface casing and 9-5/8-in. protective casing with drill pipe dropped into the well and blowout flow out the 9-5/8 in. A casing head with hanger lock-down screws is snubbed through the flow and down over a 9-5/8 in. stub by use of a venturi tube.
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A casing clamp is installed on the 9-5/8 in. stub above the casing head. Hydraulic jacks are used to pick up the 9-5/8 in. and re-tension the pipe. Tension can be directly calculated from hydraulic jack pressure. A wraparound casing hanger with integral pack-off is installed around the 9-5/8 in. and pushed into the slip bowl. The lock-down screws are run in to fully set the hanger and the hydraulic jacks are bled off. The 9-5/8 in. can then be trimmed to desired length with a pneumatic cold cutter, and the well can be capped with the assembly shown in Fig. 29.
Fig. 29. Two types of well capping stacks. In wells with only a single casing string, the wellhead is installed with slips locked in place around casing within the slip bowl and the entire well head is jacked up to tension the slips. A support base is then welded under the wellhead. (See related article, "How postcapping put Kuwait's wells back onstream," World Oil, January 1994, page 92.) Other capping or killing techniques are described here. Capping stacks come in several configurations, with the stacks in Fig. 29 used most commonly. Blind rams are used above the diverter spool to divert flow. The extra blind ram provides a back-up, as erosion can occur in some high velocity flow streams. The long bell nipple lifts flow higher above the BOPs. The high weight of this capping stack helps stabilize it as it is moved into the flow stream. Once the stack is positioned over the flow and centered in the flow stream, it can be lowered into position over the stream. BOPs are sized based on mating flange size, or larger in high-volume flow streams. Flow forces have caused unsupported capping stacks to be thrown away from the well; thus, the high weight of these stacks is actually more of a benefit than a liability. Even the massive capping stacks must be pulled or snubbed down over large blowouts or supported on a long stud bolt and spun over the flow. Spin or snubon techniques are used by firefighters to stabilize and allow installation of capping equipment in flow streams. Spin-on techniques use a long stud bolt run between the lower flange of the capping stack and the mating wellhead flange. The flanges are positioned 180، out of phase, very near one another, and one stud is dropped. The seal ring is tack welded into the lower flange of the capping stack or locked-in with set screws. The capping stack is then spun through the flow with the flange splitting the stream momentarily as it turns on the one stud into matching position. The capping stack is then lowered to bump up the flanges. One limitation of this method is that there is a greater number of personnel near the flow stream as the capping stack is spun-on. Partial flow impingement starts the second the long stud is dropped as the spin axis for the larger bodies of the BOPs. This directs flow horizontally, with more horizontal flow as the flange splits the flow stream as it is spun on. Spinning is generally used on lower-velocity flow streams, smaller valve assemblies and confined capping spaces. 70
Snub-down methods consist of pulling down the cap ping stack by running two cables through the two flanges to be mated and using winches. The cables are run 180، apart through the wellhead flange, up through the capping stack flange and clamped together around the back of the capping stack. This process is underway in Fig. 30 on a recent blowout in South Texas with a nearly 300 deg. F surface flowing temperature. The two cables are winched in, drawing the two flanges together. This is the safer method of installing capping stacks but requires more support equipment, rig-up and operational control. It is the only method that should be used on large-bore, high-velocity flows. Capping while burning was used recently on the blow out seen in Fig. 26 to limit pollution. A three-ram stack was used; this was developed and first used by the fire fighting contractor in Venezuela. This capping stack was positioned over flow out of tubing and lowered over the flow, as shown in Fig. 31. Note insulation on the BOPs, heat shielding on the capping boom and protective water spray. Most blowouts can be capped while burning. Well diversion occurs before BOPs are closed, to prevent shocking the well. This means that diverter lines and choke manifolds are connected after the capping stack is in position. Large-bore diverter spools are used on high-rate blowouts with up to dual 7-7/16 in., 5-M outlets; and 6-1/8-in. bore valves are available out of Enterra's WELLCAT rental tool inventory. Use of large-diameter diverter lines is required when tubular condition is suspect, or the well is cratered and a minimum flowing pressure is desired. If the blowout can be bullhead killed, then pumping is started and the well closed in. If well pressure buildup rate and magnitude is too high to safely bullhead, then pipe must be snubbed back to bottom to allow a circulated bottom kill. Sometimes wells are placed into production while extensive snubbing operations are undertaken or a relief well is drilled. Generally, the lowest sustainable flowing pressure, if water, oil and gas must be reliably separated, is about 150 psi. Induced bridging can be used to kill some types of blowouts. Large diverter lines and even opening up the BOPs to drop flowing pressure has induced bridging on some wells. The principal risk is creation of a shallow bridge that only diverts flow underground. Blowout snubbing or snubbing into a diverted blowout is very rare. Few snubbing supervisors have much experience in this type of operation. One of the most difficult operations is fishing dropped drill pipe or tubing to allow hydraulic reconnection to bottom or replacement with a kill string of proven integrity. Fishing with a snubbing unit within casing is generally successful. This was the case in the blowout shown in Fig. 30, as drill pipe had dropped only a few feet within the lower wellheads. Problems with buckling, flow drag, produced formation solids, scale build up and corrosion-erosion damage can be experienced. In open hole, flow out of a fish in enlarged hole can make it nearly impossible to catch the fish as flow pushes the overshot away from the top of the fish. Hook-wall guides, bent joints and even knuckle joints have not been successful in catching blowing drill pipe in enlarged hole. Snubbing on drill pipe blowouts dropped into open hole or on top of dropped fish found much deeper than expected (fish parted and dropped beside itself has a low chance of success. A relief well may be required to kill the blowout, because of the high mechanical risk of the snubbing operation. Fig. 31. Three-ram capping stack used with well burning to cap blowout shown in Fig. 26. Fig. 30. Rigging up snub-down lines. Note extra BOP on bottom of capping stack to maintain diverter line elevation off of removed rig BOPs.
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Blowout Control Technical Reference 72
Part 11 Relief wells
Part 11
Relief wells Advancements in technology and application engineering make the relief well a more practical blowout control option John W. Wright, Blowout Advisor, John Wright Company, Houston, and L. Flak, former Wright, Boots & Coots employee. This article describes evolution of the relief well in blowout control in terms of technology, strategy, planning and use . Concepts reviewed explain when a relief well is appropriate and the final section describes basic steps in design and execution of a relief well operation.
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More blowouts now warrant evaluation of a relief well as a primary control option. In the past, relief well developments in technology and strategy occurred only during unique blowout control operations. Now, how ever, a continuous process of improvement has evolved, aided by hydraulic kill models. As a result, strategic planning and new technology provide a more adaptive and efficient control option.
INTRODUCTION The relief well has traditionally been a last resort when other surface kill efforts fail. This has changed with increasing technology requirements for horizontal, deep, offshore, hostile environment, or high pressure wells. Questions arose whether blowouts of some wells could be killed at all, especially with the possibility of under ground blowouts. Fortunately, relief well advancements paralleled this period of technology growth and now provide viable blowout control options. The operator of a blowing well will likely consider surface capping methods before snubbing or relief well options. Some of the events influencing choice include: •
Is the well on fire? 74
• • • • • • •
How long will it take to clear debris? Can the well be capped once access is gained? Should the fire be extinguished, given possible pollution or H2S? If there is no fire, should one be ignited to avoid flammable gas clouds or other risks? Can the well be capped while on fire? Can it be shut-in and killed by bullheading or circulating, or should it be diverted? What if casing fails, causing an underground blowout or cratered well?
If a well clearly cannot be capped, the decision is simple-drill a relief well. But if it is uncertain whether the well once capped can be killed, then additional options remain. These include (1) rig up a snubbing or coil tubing unit to run a kill string and perform a circulation kill, (2) drill a relief well, or both. A planning team must quickly evaluate each option, associated safety risks, pollution, escalating severity, logistical obstacles, public concern, available resources, and other factors that might override preferred strategy. Complex, informed decisions must be made, especially when considering parallel surface and relief well operations. To make a decision, the operator must be aware of changes in technology, applications, planning technique, and demonstrated success. Starting a relief well plan is not only cheap insurance should initial strategy fail, but a demonstrated means of efficiently killing blowouts.
EVOLUTION OF TECHNOLOGY A change in relief well technology has always prompted a refinement in application strategy, often broadening the range of uses. Strategy has become a tool in itself, supported by software models and complex decision analysis. The original purpose of a relief well was to relieve pressure on a blowing formation by drilling a vertical well around the blowout and producing it (them) at high rates. A directionally drilled relief well on a prolific cratered blowout near Conroe, Texas, in 1933 marked the first mile stone in relief well development. New borehole survey instruments and the openhole whipstock allowed controlled directional drilling and first changes in relief well procedure from drilling vertical producing wells. A directionally drilled relief well intersected the flowing reservoir below the blowout surface location, water was pumped into the reservoir, and the well was successfully killed. Between 1933 and 1970, most relief wells followed this basic strategy. Due to limitations of borehole surveying instruments, actual distance between blowout and relief holes was subject to significant bottomhole position uncertainty. Two or more relief wells thus were often used to increase probability of gaining hydraulic communication. Early procedure was to pump water into the reservoir to communicate with the blowout well, sometimes killing the well by flooding the reservoir. Other cases required pumping weighted mud into the blowout well bore after gaining communication through a channel created by water flow, acid treatment, or fracturing. However, increased drilling depths, high GOR producers and low permeability reservoirs resulted in blowouts that could not be killed with such methods. In 1970, Shell Oil Co.'s Cox 1, a 22,000-ft Smackover exploratory well, blew out near Piney Woods, Mississippi. Accurately drilling a relief well to that depth with existing techniques was doubtful. This challenge led to the first direct intersection of a blowout tubular using a detection method. Wireline instruments were developed to detect proximity of a tubular by measuring distance and direction from the relief well to the blowout casing. Ultimately, the well was intersected and killed at 10,500 ft, with communication gained by perforating from the relief well to the blowout. This success was the beginning of
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the modern relief well, establishing strategy and planning for future relief well projects and the basis for commercial casing detection instruments (outside the Soviet bloc). Magnetostatics. In 1975, a Gulf of Mexico blowout provided economic incentive for developing the first commercial magnetostatic or "passive" casing detection tools, still in use. These instruments measure perturbations of the earth's magnetic field caused by remnant magnetic poles on the blowout casing or drillstring. Basic physics allows determination of relative distance and direction from relief well to blowout. The outer range of detection is 20 to 40+ ft depending on magnetic pole strength. This method was used on most relief wells through the mid-1980s requiring ranging on tubulars in the blowout well. Specialty kill fluids. In 1976, specialty fluids were used during a unique cratered blowout in the Persian Gulf from a high permeability gas section of the Asmari formation at 3,500 ft. Hole size was 17-1/2 in. With casing at 1,100 ft. Four relief wells gained hydraulic communication with the borehole, but were unable to control the flow with conventional kill fluids. This resulted in first use of polymer systems as kill fluids. Two polymer types were pumped through separate relief wells. An extremely viscous, cross-linked guar gum was pumped into salt cavities above the reservoir, and a high molecular weight HEC polymer was pumped into the reservoir matrix. The guar filled the cavities and decreased gas flow while the HEC blocked off loss of kill fluid to the vuggy, fractured reservoir matrix. A similar technique was successful on Mexico's offshore Ixtoc blowout in 1980. Dynamic kill. In 1978, Mobil Oil documented the technique of "dynamic kill" on a prolific gas blowout in Arun field, Indonesia.4 The technique involves circulating a light initial fluid, such as water, with sufficient friction pressure to kill the blowout (hence the name "dynamic"), followed by mud with sufficient density to contain reservoir pressure. Advantages include its use when kill pressures in the well bore must be developed in a controlled manner to prevent formation fracture; simple hydraulic calculations; and use of the relief well drillstring for real time measurement of BHP during pumping. Disadvantages include high hp requirements for killing a well with a light fluid. This technique laid the foundation for future engineered kill procedure designs. Electromagnetic casing detection. In 1980, another blowout in the Gulf of Mexico led to commercial development of the first electromagnetic "active" ranging instrument. By applying AC electric current to the blowout tubulars, a wireline instrument in the relief well can detect the induced AC magnetic field. Instrument sensors measure field direction and intensity, providing data for calculating relative distance. A blowout in 1982, using a modified technique with downhole current injection, demonstrated that casing could be detected at a range of at least 200 ft. The technique efficiently located blowout tubulars for a direct intersection. Casing detection and other developments in surveying and MWD proved a technique for triangulating the blowing well, reducing plugging and sidetracks. This again changed basic strategy for designing relief well trajectories. Accuracy meant savings; few blowouts after this date involved two relief wells. Borehole surveying technology and procedures began to advance in the 1980s. Small diameter northseeking rate-gyro systems, with greatly increased cased hole survey accuracy, became commercially available in 1982. MWD technology advanced rapidly in this period, particularly with respect to reliability, transmission speed, smaller sizes and directional instrument accuracy. Major advances were also made in under standing and correcting error sources inherent in MWD and electronic multishot surveying with respect to sensors, mechanical flexures in the BHA and BHA magnetization.
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Due to a better understanding of the earth's magnetic field and the ability to sample raw data from accelerometer and magnetometer arrays, quality control of surveys became easier. Relief wells could be targeted more precisely with better information and more confidence. Surface kill equipment. Basic requirements have not changed, but advances in high pressure hydraulic fracturing in the 1980s increased efficiency of controlling a kill operation. Skid-mounted portable high pressure pumping assemblies are easily manifolded and tandem-stacked if necessary for offshore applications. Higher hhp frac pumps are available for many land operations. All pumps can now be remotely operated from a single control point, facilitating quick changes in pump rates or kill fluids, and making kill pumping operations more coordinated and controlled. Modular high pressure manifolding systems, once custom manufactured, are now avail able in various sizes for up to 20,000 psi discharge pressures. Blowouts offshore pose problems in accessing wellheads, pumping equipment and kill lines. Steel flex hose technology allows connections to sub sea wellheads in deep water. Remotely operated valves, relief valves and hydraulic disconnect units make quick isolation of a kill line safe and practical during the kill. Computer vans or offshore modules are available for monitoring pressures and flowrates required during a kill in a single air-conditioned quiet room. The kill supervisor can direct operations in a non-hostile environment with multiple television screens plotting various data sets for quick analysis. Self-contained stimulation vessels are now available in many offshore areas of the world and make suitable kill platforms in some situations. Steerable systems. In 1988, fully steerable directional drilling systems were first used on a relief well. Using stabilized bent housing motors in various configurations with a reliable and accurate MWD system facilitates precision directional work required to drill complex relief well trajectories for ranging triangulation and direct intersections. Relef well strategy changes made this same year combined relief well trajectory and electromagnetic ranging constraints into better planning for more accurate and efficient placement of the relief well. The result. In 1989, the result of 20 years of new technology and strategy proved itself in the North Sea on the Saga petroleum 2/4-14 blowout, with a direct intersection of an 8 1/2-in. borehole at a depth of nearly 5 km.(7) No sidetracks were requred and only nine electromagnetic fixes were made. The project further led to development of a sophisticated, fully dynamic, two-phase hydraulic kill simulation. This software allows complex evaluation of many kill scenarios with various sensititivites, to determine the most efficient kill method. This capability has become a powerful tool in optimizing relief well kill strategy.
WHAT'S AHEAD Blowout contingency plans were instituted for many international operators int he early 1990s. These plans document general emergency procedures, apply newly developed control strategies to specific wells and offshore structures, and provide a basis of examination. The process has helped define and address critical problems that might be encountered in controlling a blowout with a relief well. It also allows for continuous strategy refinement. Horizontal drilling activity has resulted in BHAs capable of producing controllable dog-leg severity rates >20 deg/100 ft, increasing options for relief well trajectory design, particularly for shallow blowouts. Rugged rate-gyro survey sensors provide instrumentation for steering tools used while drilling with a mud motor. This is especially useful for drilling a relief well next to casing in a vertical blowout. Recent advances in borehole survey technology provide small diameter full inertial navigation systems, using both
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steel and laser gyros capable of mapping borehole trajectory with an uncertainty approaching 1 ft/1,000 ft of hole depth in a fraction of the usual gyro survey time. Electromagnetic detection advances have reduced uncertainty in relative distance measurements by using better measurements of the electromagnetic field. Direct measurement of distance now is possible independent of the amount of current flowing in the target at distances up to 30 ft with uncertainties of +5% of the distance. Another tool, providing measurement along the z-axis, enables placement of a vertical relief well over a horizontal blowout or other high approach angle situation. Where surface access of the blowout is possible, such as a simultaneous snubbing operation, an AC electromagnetic source can be deployed by wireline in the blowout well. A sensor in the relief well measures the induced magnetic field and determines distance and relative direction with uncertainties less than +10% of the distance. These casing detection options support a broader range of relief well design possibilities. Specialty fluids today. Two blowouts in 1993 resulted in further refinement in application of specialty kill fluids when conventional fluids (water, brine, weight mud) did not work. Conditions that call for a special fluid, or a two part reactive fluid mixture, that can set up quickly and plug off and/or separate two flowing zones include: High flow potential gas reservoir s with low fracture strength and/or very high permeability with vugs and caverns • Blowout flowpaths at vertical depths that will not allow a static kill without fracturing the formation • Two or more zones flowing which cannot be practically killed simultaneously • Supercharged recipient zones in underground blowouts which unload the kill fluid above, lowers hydrostatic below, and again allows reservoir flow. •
Fluid types used include crosslinked and linear polymers, with gel time and strength controlled by temperature and pH. Other two-fluid reactive mixtures must be pumped separately or in slugs similar to pumping a gunk plug for lost circulation. Soft plugs (diesel oil, bentonite and cement that react with water) can be successfully used in specific situations. Chemicals that will form hard plugs when properly mixed can seal off a borehole or aid in the killing process when combined with heavy mud and/or cement. Such a plug controlled a prolific gas blowout in Argentina in 1993.
QUICK PLANNING GUIDE This guide outlines non-routine steps in planning a relief well based on proven technology. The design usually requires several revisions before an acceptable plan is achieved (Fig. 33). The blowout scenario controls the planning process. If the scenario or severity changes, the relief well plan may require dramatic changes. When to start a relief well. The first step is to determine if the blowout well can be capped and killed by bullheading or circulating down existing tubulars. If there is significant uncertainty in the ability to cap the well, a pre-emptive relief well planning team should be formed (within 48 hrs of the blowout). Cost of a plan is cheap insurance should a relief well be needed and the relief well can often serve as a replacement well. If the well cannot be capped, the relief well(s) can then start as soon as possible. If the well can be capped but not killed, then use a snubbing or coil tubing unit for a circulating kill, or drill a relief well, or start both operations simultaneously.
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Planners complete basic snubbing and relief well evaluations and identify weaknesses. Blowout snubbing operations that require fishing or have high gas flowrates have a high incidence of problems. If there is major uncertainty in snubbing success, then a relief well should be started parallel with snubbing. Advantages of either may be altered by overriding factors such as pollution, safety, etc. It may be more cost effective to drill a relief well rather than snub if: A blowout can be capped, but can not be shut-in without risking an underground blowout. It can be put on emergency production while drilling a relief well. • An evaluation of risk of casing wear during fishing operations indicates likelihood of causing an under ground or broached blowout even while the well is on production. • A serious pollution problem requires the well be ignited to limit environmental damage, yet it is not practical to cap the well while burning. •
Task force. Organize a dedicated task force for planning and executing the relief well. Depending on project size, this may be a few people or a large organization. The leader should be a senior drilling engineer or drilling manager from the operating company. There may be an office planning team and a field execution team. Teams are normally broken into two functions, one planning the kill operation and the other planning the drilling and intersection pro gram. At least one relief well advisor and one senior drilling engineer should be assigned to each group. Support personnel are added as needed depending on project size. Initial decisions. Once the task force is formed, it should at least consider these questions: Does getting critical equipment, contractors and supplies involve considerable lead time? What rigs are available and are they suited for drilling the relief well? If a rig is ready, can a surface location be picked immediately and the well spudded before planning is completed? • What sizes and grades of casing will be required and are they readily available? • • •
There should always be a mechanism to update and review the decision-making process, and a careful pacing of the decision itself. Though there is always a sense of urgency in evaluating decisions during a blowout (and many can be made quickly with the help of a relief well advisor), some decisions take time and research to clarify Planning process. Relief well planning is a repetitive and parallel process requiring simultaneous evaluation of the kill pumping program and the drilling and intersection program. The kill point governs outcome of both programs. The kill point must be weighed against what is best for killing the well and what is best for drilling and intersecting. Experience will help make initial assumptions. The kill team then analyzes the kill program based on the given point and the drilling team analyzes the drilling and intersection pro gram based on the given point. If either group finds the chosen point unacceptable, it will be moved up or down the well and re-analyzed until an acceptable plan is reached. Once the chosen relief well design is presented, it should be continuously analyzed for safety, logistics, probability of success and economics (see box). Coming next: The concluding article in this series will discuss the developing role and interrelation between oil well firefighting companies, blowout engineering advisors, service companies and operators to better manage blowout control hazards.
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Table: Relief well planning considerations Iterative systematic planning • Define objectives and establish kill point Hydraulic design • Design hydraulics for various scenarios • Establish surface equipment • requirements • • Detail kill procedures • • Design casing program • • Establish relative position uncertainty • • Establish number of relief wells • • Determine initial casing search depth • Establish surface location(s) • • Design relief well and drilling kill program
Blowout fluid and reservoir properties Various kill fluids and injection rates Relief well tubular sizes and strengths Maximum predicted surface pressures Hydraulic horsepower requirements Drill string ejection pressure Kill fluid volumes and time to achieve
• Define special equipment requirements Surface equipment Kill procedures • High/low pressure pumping equipment • High/low pressure manifolding • • Tanks, mixing and transfer equipment • • Water/diesel requirements and storage • • Rig specifications and deck layout • Stimulation vessel as kill platform • •
Communication and chain of command Decision tree and detailed scenarios Testing of equipment as a system Plugging blowout and relief wells
Special and backup equipment
Establishing kill point Borehole uncertainty • Status of blowout casing and wellhead • Flow path and tubing performance • Blowout and kill fluid properties • Formation properties at kill point • Formation drillability time • Directional constraints and control • Surface and special equipment •
Survey sensors Geographic location Borehole attitude Instrument uncertainty model Instrument calibration data Field quality assurance
•
Survey comparisons
Risk analysis and success probability
Initial search depth • • • • well •
• • • • • •
Surface location • • • • ice •
Type of search instrument Blowout casing and sidetracked fish Chemical and physical characteristics Drilling mud in blowout and relief Relative position uncertainty
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Insurance and regulatory requirements, surface/ seabed hazards or obstacles Hydrogen sulfide concentration Prevailing winds, currents, waves and Heat radiation or bubble plume
Well control considerations
• • •
Shallow gas hazards and bathymetry Geologic hazards Directional and survey considerations
Well path and dogleg considerations
•
Rig type
• point •
Formation drillability near detection
•
Relief-well geometry • rates, • • •
Kickoff point, build drop and turn
•
Establishing fluid communication
formations Well control Casing detection
• • • •
Direct intersection with bit Low pressure acid or water squeeze Hydraulic fracturing Perforating guns or explosives
Survey accuracy
•
Sidetracks
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Blowout Control Technical Reference
Part 12 Incident management And critical alliances
Part 12
Incident management and critical alliances How developing these two disciplines allows an operator to more efficiently manage a blowout John W. Wright , Blowout Advisor, John Wright Company, Boots & Coots, Houston, Texas L. Flak, former Wright, Boots & Coots employee. 82
This concluding article of the 12-part series discusses reasons why operators need to establish some type of Well Control Incident Management System (WCIMS). A proposed system is presented, including five major subsystems. For operators who find these intimidating, a "minimum" program is suggested. The section on blowout control alliances discusses the evolution of oilwell firefighting and how it has become extremely competitive while the number of incidents is less than it used to be. It is suggested that this situation is "diluting" the experience level within the oilwell fire fighting industry and is, thus, generating a need for alliances between operators, contractors and subcontractors-even between operatorswhere one company's problem could involve other operators.
INTRODUCTION Today's oil and gas operator must be prepared to adequately manage a well control incident. Due to increased liability of health, safety and environmental (HSE) issues, procrastination is quickly becoming a non option. Though catastrophic blowouts happen less frequently, potential consequences for an unprepared operator are higher than ever. Recent events have shown that even blowout incidents that happen to other operators can by causing implementation of restrictive and costly government regulations. If fatalities or oil spills occur, the whole industry may be indirectly affected by negative public exposure, closing of sensitive environmental areas to leasing and increased insurance premiums. Therefore, it is in the interest of the industry as a whole, that all operators maintain acceptable levels of preparedness and critical resources to effectively manage an incident. 83
Not even a major oil company can justify having equipment and full time experienced blowout control and associated personnel on staff. However, every operator expects to easily con tract such resources when a situation arises or to assist in developing contingency plans. Strategic alliances assure effective planning, and resources will be readily available as required. Strategic alliances establish relations with critical contractors, other local operators if necessary and local and federal governmental agencies with jurisdiction in the area. A primary HSE objective for all operators is to provide a working methodology to safely and effectively manage, respond to and recover from a well control incident. The complexity of this methodology will vary with operation size and operator as well as risk and vulnerability associated with the area. A standardized "all risk" system of procedures and terminology should be used by all operators regard less of their size and operational complexity. Standards become especially critical when outside assistance and complex communication is required in a severe emergency. The fires of Kuwait closed a chapter in the oilwell firefighting business traditionally associated with a few pioneering individuals.
WELL CONTROL INCIDENT MANAGEMENT SYSTEM Fig. 35. Complicated blowout control projects can be more effectively managed by alliances between operator, firefighter, blowout control advisor and critical support contractor. The National Inter-Agency Incident Management System (NIMS) and the Incident Command System (ICS) were developed in the U.S. as a consequence of fires that consumed a large portion of Southern California in 1970.1 As a result of those fires, a need was identified to develop a system whereby diverse groups could work together toward a common goal under emergency conditions. This basic model has since been adopted by many industries to more effectively manage emergency incidents for all types of hazards ranging from oil spills to hostage situations. Fig. 34 (button) above is an example ICS organizational chart. Proposed system. Based on NIMS and basic hazard control models, a management system is proposed that consists of five major subsystems which collectively provide a total system approach to well control incident management. These include: 1. Hazard management. Identifies well control hazards and assesses risk and impact of the hazards. It identifies: 1) current controls to minimize hazards, 2) ability to respond to and mitigate an incident, 3) controls to minimize incident escalation, and 4) ability to recover from an incident. Based on this vulnerability assessment, additional controls are put in place to manage risk at an acceptable level. 2. Incident management. Customizes ICS for the operator and area. It combines: facilities, equipment, personnel, procedures and communications operating within a common organization to respond to a well control incident. To function properly, its users utilize eight underlying components of organization: common terminology, modular organization, integrated communications, unified command structure, consolidated action plans, manageable span of control, pre-designated incident facilities and comprehensive resource management. This system manages incident effects as well as source control and is designed for an all-risks response. Complexity of this modular system would depend on out come of the hazard/risk assessment and individual incident nature.
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3. Qualification management. Deals with: pre-qualification and training of critical personnel and con tractors; training on, for example, procedures and policies, well control, safety and emergency response, risk and hazard management; development and implementation of emergency drills; and certification of critical jobs. This subsystem is designed to assure that critical personnel and contractors are trained and qualified to perform assigned duties. 4. Information management. Deals with identifying and having rapid access to critical information, that it is up-to-date and accurate and that QA/QC procedures are in-place for critical control and response operations. It assures that information gained in associated subsystems is available in a usable format. 5. Technology management. Assures that proper procedures and critical equipment exist for responding to and mitigating the incident. This would include spill containment, fire fighting, surface intervention on land, surface intervention offshore, subsea intervention, drilling relief well(s), planning and executing kill operations and final P&A or well recovery. Procedures and equipment do not necessarily exist for all possible blowout control operations. This discovery would be made through hazard assessment and contingency plans. Due diligence. What is reasonably expected of an operator in the normal or logical course of events with respect to being prepared to respond to a well control incident? Unless governed by local or federal regulations, preparedness degree is largely left to the individual operator. This works fine until a blowout control effort results in fatalities, severe injury or major pollution. The degree of preparedness may then be contested in a court; or a regulatory agency may automatically assume the local industry as a whole is not sufficiently prepared and introduce compliance regulations on the rest.(2) If all operators were to voluntarily follow the basic steps outlined in the pro posed WCIMS, or similar system, catastrophic incidents and compliance regulations could be minimized. A minimum system. At first glance, expansion of the five subsystems in the proposed WCIMS appears as if it could overwhelm many operators. Complete expansion, however, is generally only justified when working in very high risk areas, such as an H2S or high-pressure gas field near populated areas, or extremely sensitive environmental areas. Therefore, if an operator is starting from scratch, or wishes to assess its current preparedness level against a proposed system, the following describes a minimum guideline. Hazard management. An operator must have a reasonable idea of basic blowout hazards associated with a given field or planned drilling activity, and likely consequences, where it operates. This hazard assessment is generally going to be subjective as industry statistics on blowout incidents are generally unreliable due to small sample size and the large number of independent variables associated with each. The assessment should be documented, with reasons to back up the opinion. Based on this initial judgment, an operator will decide whether additional detailed hazard assessment and control evaluation is warranted beyond acceptable standard operating/design practices. If justified, hazard analysis expansion should be continued until cost effectiveness based on total field investment and potential liability begins to diminish. Incident management. Based on the amount of risk associated with the operating area, an Incident Management System should be devised and documented. This should include details on how the operator is going to ramp-up from normal operations to a blowout response, depending on severity level. Usually no more than three levels of response are justified. For example, a kick might be classified as a Level 1 incident, a suspected under ground cross flow Level 2 and an uncontrolled surface or underground blowout as Level 3. A Level 3 incident may escalate as a Level 1 ramp-up or may happen suddenly. Detailed procedures should be documented for implementing the ramp-up for each level, for example: who calls whom?; who is in charge of what?; what is each person's responsibilities?; what field supervisory personnel should/should not do during each level?; what equipment and outside personnel should be mobilized and so forth?
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The ICS is the recommended structure on which to build this system as it is designed to expand and contract from a single Incident Commander to handle a small problem, to a large, multi-disciplined organization to handle a large-scale disaster. At a mini mum, it should include time frame for the initiating incident, escalation to blowout and response team(s) placement. Systems for higher-risk areas should expand the time frame through source control planning/execution and final blowout recovery. Qualification management. Each person in the ICS should have basic training and job descriptions. Critical contractors, such as oilwell firefighting companies and blowout advisors, should be pre-qualified. For example, some personnel may have considerable experience in capping Kuwait wells but no experience in capping a well while burning, drilling a relief well, subsea intervention, or planning and executing a complicated kill operation. Call-off contracts should be placed with at least two oilwell firefighters, as one company may not have the required personnel avail able when called. Critical support con tractors should know what their job responsibility is and where they fit into the operator's ICS structure. Failure to do this prior to the incident will cause individuals in the project to work out their own "pecking order" within the structure, hindering effective teamwork. Information management. An operator should be able to immediately gather whatever information is required to implement ramp-up for blowout response. This includes an emergency response plan with documents located at field locations and offices, as well as with all responsible managers in the ICS structure. Any additional information that blowout control teams may need based on incident type should be capable of being compiled within 8-24 hours of the emergency. If this is not currently possible, action should be taken to assure that required information is compiled and updated. Technology management. For source control, the operator should confer with its chosen firefighter con tractor and blowout engineering advisor. This decision would be made based on initial hazard assessment. Situations that should trigger further evaluation include: deep HPHT wells; geothermal wells; subsea wells in deep water; unique platform designs; unique tree, wellhead or BOP designs; remote locations; environmentally sensitive areas; wells near population centers or H2S wells; high flowrate gas wells, multiple-well congested plat forms; and other unique or unusual situations. Following this format, an operator with a relatively low-risk well or field could assemble a minimum SCIMS in a relatively short time and on a tight budget.
BLOWOUT CONTROL ALLIANCES Changing operating company philosophies in the last few years resulted in more long-term alliances being formed between drilling contractors, service companies and vendors, to reduce costs and increase efficiency. This trend is logically expanding to blowout control. The first call-off contracts designed specifically for blowout control services were developed during pre-planning operations prior to the Kuwait fires in late 1990. These contracts covered fire fighters as well as critical support services. Speed and efficiency at which the wells were controlled demonstrates pre-planning effectiveness and close working relationship developed between various oilwell firefighting companies, support contractors and operators. Since blowout control operations are relatively rare events, formation of an alliance between operator, fire fighter and critical support contractors makes good strategic sense-a contingency plan on the shelf is not enough! An operator with a catastrophic blowout needs to develop and test procedures, acquire confidence and build a team with the critical con tractors, Fig. 35. Oilwell firefighters. Blowouts and fires have followed our industry from its earliest days. H. S. Patton and M. M. Kinley are credited as being the first dedicated oilwell firefighters; their careers started in the 1920s30s. The next generation included Red Adair, Boots Hansen and Coots Matthews, all starting initially with
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Kinley and later forming their own companies. It was with that generation that the firefighting aspects of their job description became secondary to controlling the blowout flow. For many years, only one or two companies could be supported by the available blowout demand. While this did not allow for tremendous competition, an operator knew the people working on their well had a broad experience base. At the time of this writing, some 10 privately held companies exist worldwide, plus additional national teams, all competing for less work than existed when there were only two companies. Most of these companies came into existence during and after the Kuwait fires of 1991. Too many firms sharing too little work means not only immediate problems for the firefighting companies, but potentially for the industry in general. The net effect is a dilution of experience base in all individual companies. Coupled with increased consequences, this makes operators more vulnerable than ever to a catastrophic blowout. Market forces will eventually correct this problem, but that will also change forever the business traditionally associated with a few pioneering individuals. Surviving companies will have to be more diversified "one stop shops" offering full general contracting services with strong engineering component resources. This will include, for example: traditional fire fighting/blowout control services, snubbing, hot tapping, valve drilling, freezing, cold cutting, relief well planning and supervision, kill planning and supervision, development of WCIMS, training, field inspections, audits, engineering support, etc. The full service oilwell firefighting company will be the hub alliance with the operator for blowout control. In some cases, it will be more efficient for support services to be sub contracted by the firefighter than for the operator to juggle various con tractors during an emergency. In other situations with larger operators who already have contracts with major service companies, the fire fighter will primarily play the part of expert advisor. All operators should pre-qualify the oilwell firefighting companies they plan to use in an incident, set up call-off contracts, and jointly evaluate their current vulnerability level, area by area. Blowout engineering advisors. In 1990, major international operators began using blowout engineering advisors to help advise their personnel on blowout contingency plans as well as actual blowouts. Their strategy was to help develop engineering expertise in the blowout-control industry to sup port oilwell firefighters and service companies, and to better prepare their internal management to handle a blowout control operation. This has led to development of engineering divisions or engineering alliances with most of the firefighting companies. This is a historical change from the traditional hands-on approach used by past firefighters. This development is probably more significant than any new technology in the innovation and refinement of blowout control, response and management. As stated in Part 1 of this series, blowout control management and engineering has always relied on a few experienced individuals. These individuals worked for operating companies and gained experience in an era where blowouts were more common. All of these men have retired, or will shortly, leaving an experience gap. Combined with the diluted experience base within the firefighting companies, this leaves a gap that will eventually be bridged by blowout engineering advisors. The future role of blowout engineering advisors will be mutifaceted. Of course they must be available to respond to a blowout crisis and assist an operator or firefighting team on control options and kill procedures, but the more important role will be filled in preplanning, documenting procedures, adapting technology and developing new techniques. This will require joint efforts between operators, service companies and fire fighters. Emphasis on HSE will eventually put blowout control on every operator's list of hazards to manage. Blowout advisors will assist in identifying blowout hazards in existing fields and future drilling projects. Once identified, hazards must be assessed as to risk of occurrence, consequence and ultimate impact.
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Depending on the impact, specific contingency plans may be justified to help reduce risk to acceptable levels and identify short falls in equipment, techniques and emergency management procedures. Additionally, the advisor will perform audits on emergency response plans, inspect platforms and rigs, assist in conducting simulated emergency response drills for blowout control and eventually become involved in design of facilities before they are built. Support contractors. Depending on type and location of the control operation, various support contractors will be required. These might include con tractors for: drilling, pumping, drilling fluids, drilling/fishing tools, directional drilling and MWD, wireline logging, safety and toxic gas detection, civil works and heavy lift, airlift, crane barges, support vessels, diving and specialty blowout control equipment. Services that may be required include: choke manifolds and diverters, capping stacks, abrasive and explosive jet cutters, demolition explosives, cold cutters, snubbing units, coiled tubing units, production separators, inflatable packers, perforating guns, specialty kill fluids and electromagnetic ranging equipment. The type of operations (drilling, production, workovers, other), operating area (land, offshore, remote), and size and organization of the operator (major, large or small independent, emergency management centralized or decentralized) will dictate which contractors are considered critical. If a firefighting company is under call-off contract for a particular area, most specialty blowout control equipment can be subcontracted or coordinated through that company. The remaining major service contractors will generally be readily available in a developed operating area. If the area is remote, the operator will probably have con tracts in place for most required services. The operator's WCIMS should clearly indicate which services are critical for an area and whether direct con tracts should be in place and which should be subcontracted through the firefighter. Other operators, government agencies. As previously mentioned, it is in the best interest of all operators to minimize blowout effects in their area whether it is their well or not. Alliances between operators to share non-confidential information, critical equipment and supplies during a blowout or on contingency should be evaluated in certain high-risk, remote, or sensitive operating areas. Incident management plans should address the role of any government agencies with jurisdiction in the area. These should be spelled out in the ICS and confirmed with representatives of such agencies. In some cases, where severe pollution is occurring or possible, or population centers could be affected, these agencies have authority to stop actions, even take over operations and proceed as they see fit-the operator, of course, maintaining all financial liability.
CONCLUSIONS This article concludes the 12-part series on blowout control, response, intervention and management. The purpose of the series was to help operators better understand and manage well control incidents today and into the future. The industry has changed, blowout control engineering and management experience has been redistributed, and conclusion of the fires of Kuwait closed a chapter on traditional oilwell firefighting companies' modes of operation. These changes, along with increased HSE liability makes it imperative for operators to develop WCIMS and create critical alliances.
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