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«Paper #2-11 SUBSEA DRILLING, WELL OPERATIONS AND COMPLETIONS Prepared by the Offshore Operations Subgroup of the Operations & Environment Task Group ...»

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Requirements for completion equipment found in 30CFR250.806 were modified in January 2010 to deal with HPHT completions. Although the rule explicitly mentions sub-surface safety valves (SSSV), there are far-ranging implications due to the clause inserted in the rule pertaining to “related equipment”. The new requirements are that when a lessee or operator plans to install SSSVs and related equipment in an HPHT environment, the lessee/operator must submit detailed information with their Application for Permit to Drill (APD), Application for Permit to Modify (APM), or Deepwater Operations Plan (DWOP) that demonstrates the SSSVs and related equipment2 are capable of performing in the applicable HPHT environment. The detailed

information must include the following:

• A discussion of the SSSVs’ and related equipment’s design verification analysis.

• A discussion of the SSSVs’ and related equipment’s design validation and functional testing process and procedures used.

• An explanation of why the analysis, process, and procedures ensure that the SSSVs and related equipment are fit-for-service in the applicable HPHT environment.

The BOEMRE also issues Notices to Lessees (NTL) to provide interim requirements until the agency can establish laws through normal rulemaking channels. The regulatory controls for subsea completions were acknowledged by the MMS in 1998 to be behind the current technology (Alvarado, 1998) due to lagging regulatory capacity attributed to limited resources, increasing coordination needed among federal, state, and local agencies, and lack of standards Related equipment includes wellheads, tubing heads, tubulars, packers, threaded connections, seals, seal assemblies, production trees, chokes, well control equipment, and any other equipment that will be exposed to the HPHT environment.

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for some downhole equipment. The Deepwater Horizon incident, and associated Macondo well blowout, has driven regulatory activities to a fever pitch since April 2010 as the industry, lawmakers, and regulators struggle with how to manage safety and environmental aspects of drilling and completing deepwater oil and gas wells.

After the Macondo blowout, but before the root cause was established, industry task groups made recommendations to the Secretary of the Interior on how to improve safety in well operations. Those recommendations were adopted and formalized into a Department of the Interior report to the President (DOI, 2010). Many aspects of the report were covered when the BOEMRE issued two new NTLs to operators in OCS waters of the Gulf of Mexico. In addition, an NTL was issued that temporarily imposed a moratorium on offshore drilling (NTL 2010N04). The two NTLs affecting remaining operations are summarized below.

• NTL 2010-N05 (MMS, 2010). Although a legal challenge later led to invalidation of this

NTL, its original provisions set a significant tone by requiring that each operator must:

o Examine all well-control system equipment (both surface and subsea) currently being used to ensure that it has been properly maintained and is capable of shutting in the well during emergency operations. Ensure that Blowout Preventers (BOPs) are able to perform their designated functions. Ensure that the ROV hot-stabs are function-tested and are capable of actuating the BOP.

o Review all rig drilling, casing, cementing, well abandonment (temporary and permanent), completion, and workover practices to ensure that well control is not compromised at any point while the BOP is installed on the wellhead.

o Review all emergency shutdown and dynamic positioning procedures that interface with emergency well control operations.

o Ensure that all personnel involved in well operations are properly trained and capable of performing their tasks under both normal drilling and emergency well control operations.

In addition, operators were directed to submit to BOEMRE: (1) a general statement by the operator’s Chief Executive Officer (authorized official) certifying the operator’s compliance with all operating regulations at 30CFR250 and (2) a separate statement certifying compliance with each of the four specific items above. Finally, NTL 2010-N05 required certification from an independent third party regarding the condition, operability, and suitability of the BOP equipment for the intended use and the operator must have all well casing designs and cementing program/procedures certified by a Professional Engineer, verifying the casing design is appropriate for the purpose for which it is intended under expected wellbore conditions. While not specifically mentioned, it was inferred that subsea completions would come under the same scrutiny as the drilling operations and well-construction products/practices.

• NTL 2010-N06 (BOEMRE, 2010a). The NTL effectively rescinds a previous NTL (2008-G04) that relaxed the information required from operators in their applications

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to the BOEMRE (previously, MMS) with respect to blowout scenarios. As a result of this NTL, operators are now required to provide in-depth analysis of blowout scenarios along with calculations on probable discharge rates followed by measures taken to prevent and reduce the probability of a blowout and also measures that the operators are proposing will be taken in the event of a blowout.

The BOEMRE Drilling Safety Rule (Federal Register, 2010a) prescribes proper cementing and casing practices and the appropriate use of drilling fluids in order to maintain wellbore integrity.

The regulation also strengthens oversight of the BOP and its components, including remotely operated vehicles, shear rams and pipe rams. Operators must also secure independent and expert reviews of their well design, construction and flow-intervention mechanisms.

The BOEMRE Workplace Safety Rule (Federal Register, 2010b) requires offshore operators to have clear programs in place to identify potential hazards when they drill, clear protocol for addressing those hazards, and strong procedures and risk-reduction strategies for all phases of activity, from well design and construction to operation, maintenance, and decommissioning.

The Workplace Safety Rule makes mandatory American Petroleum Institute (API) Recommended Practice 75, which was previously a voluntary program to identify, address and manage safety hazards and environmental impacts in their operations.

Safety Management. The safety management of different types of subsea completions has been reviewed in previous industry publications (Cooper, 2008; King, 2001; Fahlman, 1974). The safety aspects can be distilled into the following categories: (1) risks to personnel, (2) risks to the environment, and (3) risks to equipment or operations.

Risks to personnel occur during normal installation and operations of the subsea completions and are effectively covered by Workplace Safety Rule mentioned above. Since subsea completions effectively remove personnel from the vicinity of operations during production, risks to personnel are minimized. However, some have argued that having personnel in the vicinity of operations also allows continuous monitoring and prevention of problems due to observations prior to complete failures. The remoteness of exploration and production in subsea applications makes access to medical treatment facilities limited unless standby vessels are in use throughout the drilling and completion process.

Risks to the environment are similar to other oil and gas well drilling operations. Unintended releases of hydrocarbons to the environment can occur during drilling or completion of the well.

An effective barrier strategy including both fixed and operational barriers increases the overall reliability of the completion so the environmental risks are minimized. As described in the status report by BOEMRE (2010b), an API task group is developing a Recommended Practice for the Design of Deepwater Wells that effectively outlines barrier strategies and provides recommendations for their selection, maintenance, and replacement if damage occurs.

Risks to equipment or operations also are similar to those in other oil and gas well drilling operations. Qualitative risk assessments and subsequent risk management are key to minimizing risks. Those measures may be simple items such as developing a more robust tubing or drill pipe

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connection (Griffin et al., 2008) or more complex such as developing an electric control system for a subsea tree that includes automatic shut-down capabilities (Bouquier et al., 2007).

Economics. The primary economic advantage of a subsea completion can evaporate instantly if a workover is required. The subsea wellheads are designed so that workovers are possible by reentering the well but mobilization of floating workover rigs and the day-rate costs of those vessels make all but the most serious operations to be cost-prohibitive. As a result, many subsea completions will be left alone until the end-of-life is reached. Design requirements of 20 to 25 years for completion equipment are not uncommon. Advances in well intervention to reduce cost and improve operational capability are required to further enhance the economic attractiveness of subsea completions.

Technology. The barriers and opportunities of subsea completions related to the application of technology for completing oil and gas wells fall into four categories: general, production trees, installation issues, and production issues.

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General technological aspects of subsea completions are concerned with the materials and environment of the wells. Typically, the cost of interventions drives operators to select materials which have known survival rates in the estimated downhole environment. With possible well changes from producers to injectors and potential reservoir souring, high alloy materials are generally selected to insure life-of-the-well performance regardless of their cost multiplier over conventional alloys. Material availability in large-bore components can sometimes be an issue as well as delivery in volumes as required for subsea field development.

Since the completion of subsea wells began, the push to deeper and deeper water to reach more and more hydrocarbons seems to be an unstoppable march. Drilling and completing exploratory wells is replete with risks relative to unknown pressures, temperatures, and gradients of pressure that may change quickly due to geologic conditions. Shallow gas is one example of a drilling hazard that must be adequately anticipated and managed during well construction.

Depending on the reservoir location, HPHT conditions may exist in the wells. This may require extensive product development (Bradley et al., 2006) to safely contain the elevated pressures and temperatures. The effect of temperature on the material performance has been extensively studied and data are widely available (for example, ASME, 2010). But beyond temperature effects alone, subsea completions and associated surface equipment may suffer from tension or torsional loads as a result of the completion type (particularly compliant towers and spar installations). Those cyclical loadings on the surface or seafloor equipment, when combined with HPHT conditions, may require a crack fatigue investigation to fully understand the life of the equipment. In addition, the effect of the produced fluid on the metallurgy under such situations, along with any required inhibition methods for corrosion or cracking, must be investigated and understood. A proposed API Technical Report to guide HPHT product development is in work (“Protocol for Verification and Validation of HPHT Equipment“, API Technical Report PER15K-1, publication expected in 2011).

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Early subsea completions discovered the need for horizontal trees to allow access to the main bore of the well without removing the tree or disturbing any external connections to flow lines (Skeels et al., 1993). Those trees have grown in both capability and complexity, including electric-operated subsea production trees which were introduced in 2008 as a means to reduce lost production days. Production availability gains of 2% were reported along with a cost advantage of 12.4% (Bouquier et al., 2007).

One of the current issues with subsea wells is that the annuli between successive casing strings can become pressurized as an undesirable consequence of operations. The pressure is created by having a sealed annulus containing fluids which are initially sealed at a lower temperature but later heated during production, thereby causing an increase in the annulus pressure. API RP90 recommends methods to deal with that pressure and design tubulars to contain it.

• Installation and Production Technologies The installation of the subsea completion generally involves two strings of tubulars. The first string consists of the tubulars installed in the producing interval (sometimes called the lower completion) while the second string exists inside the production casing from the lower production packer to the production tree (called the upper completion). Both strings have specific issues to be addressed.

The lower completion in subsea completions (and particularly for deepwater completions) is generally a sand-control completion. The requirement for sand control is driven by the types of formations that are encountered in subsea wells (Waltman et al., 2010). Since the water “overburden” is less dense than rock, the lower formations are not typically well consolidated and therefore require a sand control completion to prevent the unwanted development of formation fines during production. Those types of sand-control completions may either be installed in open hole or cased hole and are characterized by an upper packer, a series of gravelpacked screens, and a lower sump packer.

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