Big bore completions (i.e., those using 6–5/8-in. and larger production tubulars) are required for economical production and injection in prolific reservoirs. A variety of completion configurations exist, though only the most traditional schemes have been discussed.
This paper will present the results of a study that analyzed and evaluated more than 350 large bore completions over a 20-year span to determine best practices. The study formed the basis for a new approach to well design that merges wellbore construction with the completion. The paper will discuss this approach, which includes a classification system to help operators choose the optimum design to match their completion objective.
This paper will begin by reviewing the big monobore concept, discuss various enabling technologies and their opportunity to increase production while reducing costs, review configuration choices with case histories and conclude with a case history that illustrates how the big monobore concept is evolving in the world's largest gas field.
Big Concept
For prolific reservoirs, big monobore completions can significantly improve production rates while decreasing both capital and operating expenses. Enabling well construction and completion technologies have resulted in completion components and systems that can further reduce expenses while reducing associated risks.
Advantages.
Big monobore completion benefits include: elimination of gas turbulence areas; elimination of restrictions on production and use of intervention tools; earlier return on investment; exploitation of the reservoir through fewer wells and fewer slots on a platform; possible elimination of one or more platforms; lower long-term operating expense from quicker depletion of the reservoir and fewer wellbores; and lower topsides and maintenance expenses.1,2
These benefits can translate into hundreds of millions of dollars in savings. Conoco has reported that it improved overall project economics of its North Sea Heidrun Tension Leg Platform (TLP) by more than $108 million by using 7-in. rather than 5–1/2-in. tubing and tree.3
One study compared a hypothetical development scenario using 5–1/2-in., 7-in., and 9–5/8-in. production tubing. Exploiting the reservoir required twenty three 5–1/2-in. wells delivering 145 MMscf/day for a cost of $263M, fifteen 7-in. wells delivering 235 MMscf/day at a total cost of $215MM, or eight 9–5/8-in. wells delivering 450 MMscf/day at a total cost of $190MM. The project NPV of using the larger tubing size is augmented by being able to deplete the reservoir two years earlier than a 5–1/2-in. program and just over one year earlier than a 7-in. program.4
Risk Reduction.
Achieving accelerated production with fewer wells places greater emphasis on reliability. The negative impact on production of one large-bore well that is unable to flow is significantly greater than that of a single conventional completion. This risk factor is usually the most difficult part of the economic feasibility to compute. Many operators use a combination of their organization's average downtime per well, industry averages for similar completions.
Risk reduction includes contingencies to complete extra wells for reserve deliverability and the use of various methods to verify equipment performance and reliability.
As with any critical well, two methods can be used to both minimize risk and lower costs:use of pre-qualified components that have been tested according to an industry performance standard (i.e., API 14A for safety valve, and ISO 14310 for completion packers), anduse of a single, original equipment manufacturer (OEM) who can supply components from the safety valve to the liner shoe.
Advantages.
Big monobore completion benefits include: elimination of gas turbulence areas; elimination of restrictions on production and use of intervention tools; earlier return on investment; exploitation of the reservoir through fewer wells and fewer slots on a platform; possible elimination of one or more platforms; lower long-term operating expense from quicker depletion of the reservoir and fewer wellbores; and lower topsides and maintenance expenses.1,2
These benefits can translate into hundreds of millions of dollars in savings. Conoco has reported that it improved overall project economics of its North Sea Heidrun Tension Leg Platform (TLP) by more than $108 million by using 7-in. rather than 5–1/2-in. tubing and tree.3
One study compared a hypothetical development scenario using 5–1/2-in., 7-in., and 9–5/8-in. production tubing. Exploiting the reservoir required twenty three 5–1/2-in. wells delivering 145 MMscf/day for a cost of $263M, fifteen 7-in. wells delivering 235 MMscf/day at a total cost of $215MM, or eight 9–5/8-in. wells delivering 450 MMscf/day at a total cost of $190MM. The project NPV of using the larger tubing size is augmented by being able to deplete the reservoir two years earlier than a 5–1/2-in. program and just over one year earlier than a 7-in. program.4
Risk Reduction.
Achieving accelerated production with fewer wells places greater emphasis on reliability. The negative impact on production of one large-bore well that is unable to flow is significantly greater than that of a single conventional completion. This risk factor is usually the most difficult part of the economic feasibility to compute. Many operators use a combination of their organization's average downtime per well, industry averages for similar completions.
Risk reduction includes contingencies to complete extra wells for reserve deliverability and the use of various methods to verify equipment performance and reliability.
As with any critical well, two methods can be used to both minimize risk and lower costs: 1) use of pre-qualified components that have been tested according to an industry performance standard (i.e., API 14A for safety valve, and ISO 14310 for completion packers), and 2) use of a single, original equipment manufacturer (OEM) who can supply components from the safety valve to the liner shoe.
