Field development, subsea well completion design, and completion installation in Shell/BP's ultra deepwater Na Kika field development required the marriage of several new technologies and completion methods. While many of the new techniques had been implemented separately in recent completion programs in the Gulf of Mexico and abroad, this completion program brought many of them together for the first time. Reservoir uncertainties such as compartmentalization, proximity and connectivity between gas- and oil-bearing reservoirs, and aquifer size made it necessary to design a development plan for maximum flexibility. Intelligent well technology was required to mitigate these uncertainties in two of the five Na Kika fields, enabling an economic development. The final development plan for Na Kika featured four intelligent wells that would develop reserves from a total of eleven discrete reservoirs. Required functionality of these wells included competent sand control with low completion skin, remote zonal control, and continuous pressure/temperature monitoring capability for each zone. This functionality enabled producing reservoirs to be commingled or isolated as well as reservoir diagnosis to be performed remotely from the host facility, allowing optimal assessment of reservoir drainage and depletion management. This paper will discuss the economic drivers for the intelligent well completions at Na Kika, design challenges in fluid-loss control and zonal isolation during installation, and novel use of the interval control valves as well suspension barriers. Completion operations are discussed in detail to illustrate the benefits of the intelligent well functionality during installation. Introduction The Na Kika Development is located 144 miles southeast of New Orleans, Louisiana, in water depths ranging from 5,800 to 7,000 feet in the US Gulf of Mexico.1,2 The project is a subsea development of five small- to medium-sized independent fields tied back to a permanently moored floating development and production host facility, centrally located in Mississippi Canyon Block 474 in 6,340 feet of water. Na Kika is the first deepwater application of the concept of a dispersed subsea development tied back to a centrally located deepwater host that does not depend upon a single large accumulation of oil and gas. The core Na Kika development is comprised of five moderately sized (20 to 100 MMBoe) fields, containing both oil and gas reservoirs (Fig. 1). Individual reservoirs in each of the fields contained recoverable reserves as small as 10% of the field totals. The play type can be characterized as amplitude supported, structural-stratigraphic traps in the middle to upper Miocene of the Eastern Gulf of Mexico. The moderate size of the average Na Kika field is a direct function of the geologic setting and nature of the channel/levee systems encountered. A wide variety of sub-facies is found in these systems, with an associated wide range in reservoir quality/type. Two of the five fields at Na Kika featured multiple stacked pay sequences, requiring stacked completions to enable an economic development concept. Stacking multiple completions in a single wellbore carries risks such as differential depletion and crossflow, or early water breakthrough, requiring costly well intervention. Intelligent well technology was employed in four of the ten Na Kika wells to manage the production uncertainties associated with commingling and to avoid well intervention.
The installation of a subsea tree from a floating drilling rig is one of the most complex and time-consuming portions of a deepwater subsea well completion. Removing subsea tree installation from the rig "critical path" would yield a step-change reduction in the time and cost to complete a subsea well. Disappearing plug technology holds the key to achieving this improvement. Regulations (and good practice) dictate the use of a plug set in the tubing hanger of a completed well to provide a barrier to well flow. Until recently, most subsea trees were installed from the drilling rig on a completion riser, after the BOP stack and marine riser were removed. The completion riser also provided the conduit to remove the tubing hanger plug. "Disappearing plug" technology eliminates the need for the completion riser and drilling rig during subsea tree installation because it acts as a well barrier, performing the same function as the tubing hanger plug, until it is opened remotely from the host facility. This paper discusses the application of disappearing plug technology to a subsea project, the synergies created between downhole completion operations and subsea installation activities, and the resultant time and cost savings. Introduction One of the largest components of the cost of a deepwater subsea development is the day-rate of the drilling rig and equipment spread used to drill and complete the wells. Roughly two thirds of completion costs are directly related to the time it takes to complete a well. Therefore, any significant activities that can be removed from the rig "critical path" will generate a substantial reduction in the capital cost of completion. Subsea well completion operations conducted from a rig include not only the downhole completion work, but the installation of subsea trees and other equipment.Subsea trees are normally run on some type of completion riser, which is run from the main derrick. Running a tree in this manner requires that the marine riser and BOP stack be removed, a time-consuming and costly operation. Other subsea equipment installation techniques, such as running on wire from an installation vessel or a rig-based winch, could be made suitable for installation of subsea trees. However, a completion riser system must still be run at some point to remove the required tubing hanger plug that blocks well flow until the subsea tree is installed. The key to enabling non-rig based tree installation is to replace the tubing hanger plug with an "alternate barrier system" to prevent well flow when the BOP stack is removed, but permit opening of the well remotely when required, without well intervention. Such an alternate barrier, or "disappearing plug" system, has now been employed successfully in the three-well Crosby (MC-899) development in the GOM. Use of an alternate barrier system downhole enabled subsea tree installation and activation without the need for a completion riser. Time savings associated with not having to trip the BOP stack multiple times resulted in the completion of the Crosby wells in less than 60% of the expected time and 20% below budget.
The Ursa-Princess Waterflood (UPWF) targets the Lower Yellow sand, the main reservoir in the Mars-Ursa basin in Mississippi Canyon, about 60 miles south of the mouth of the Mississippi river in the Gulf of Mexico, USA. The Lower Yellow sand, a world class Upper Miocene turbidite reservoir, has been on production in the Ursa and Princess fields since 1999, and has been drawn down nearly to the bubble point. The waterflood is intended to increase and stabilize reservoir pressure, and to improve sweep efficiency. To accomplish this, four subsea injectors were designed and constructed to inject treated seawater at some 40,000 bbl/day each for a target life of 30 years.As the Lower Yellow reservoir was already highly depleted, unique risks were identified in the planned subsea completion operations, to be conducted from a Mobile Offshore Drilling Unit (MODU). Seawater, used as a completion fluid, was expected to be up to 4000 psi overbalanced to the reservoir, depending on the well location. This created the risk of either uncontrollable fluid level drop in the marine riser or extreme impairment to the sandface completion. In order to maintain well control with a fluid level at the surface and still deliver low skin completions, multiple design and procedural issues needed to be addressed, including:1. Control systems on the rig and riser system to prevent uncontrollable fluid level drop, 2.Perforating systems to minimize impairment in a high overbalance environment without adding undue risk to well control, 3.Pill designs that could both control fluid loss at the sand face and clean up effectively, 4.Downhole completion systems capable of functioning either under very high pressure differentials or against very high loss rates, 5.Development of high burst screens that could withstand pilling in the event mechanical fluid loss devices failed. As more Deepwater reservoirs approach depletion, specialized tools and procedures will be required to continue to deliver safe and effective sandface completions from floating rigs. This paper details many of these considerations, and summarizes the execution experience and results for one such reservoir.
The Coulomb field is the 6th field of the ultra deepwater GoM Na Kika subsea development. The two subsea tie-back wells in the Coulomb development (the C-2 and the C-3) were completed in April and May of 2004, in 7,570' of water depth. When completed, the Coulomb wells held the industry record for the deepest water depth subsea completions in the world. The subsea trees and the surface-controlled subsurface safety valves also represented the deepest set to date. The development planning included selection of the optimum completion design to address a wild-cat in the northern block, which had not previously been penetrated. While the conceptual sand control design was based on data from the previously appraised southern block. The execution phase was performed on a Generation 5 Moored Mobile Offshore Drilling Unit (MODU) with no prior experience in deepwater completions. Value creation activities were employed to raise the awareness and competence of the rig team to transform improvement opportunities into high performance goals. The Heave-Compensated Landing System (HCLS)1 was used to install the subsea tree, tubing head spool and well jumpers from anchor handling vessels, hence expanding the scope of activities performed off the critical path of the rig and contributed significantly to the record-breaking pace. Completion fluid, workstring and treatment fluid were carefully selected and tested for well-specific conditions. Specific challenges included the quick turn around completion design and execution on a wild cat, optimizing the drill/complete sequence to complete in uncertain mineralogies, high day rate leading to a desire to be "quick but good", cooling effects due to huge riser volume and long riser trip times. Through extensive preparation and the use of several innovative concepts, record performance was achieved. This paper also gives an overview of the application of internal plastic coating of the production string in the Coulomb wells. Through nodal analysis with a match to the well performance data, it is demonstrated that the reduced tubing friction associated with the use of internal plastic coating in the tubing has been estimated to yield a 15% increase in daily production in these wells. Success in this application further proves the effectiveness of today's new and novel coating system. Introduction The Coulomb field is located 144 miles southeast of New Orleans and covers two leases, MC613 (66.7% Shell, 33.3% Petrobras) and MC657 (100% Shell). The two-well program involved the development of gas and associated liquids from two subsea clustered well locations in water depths of 7,570 feet. The Coulomb field consists of a single reservoir that is structurally separated into two accumulations. The larger, southern accumulation which had been proven and appraised by the downdip exploration well and an updip appraisal sidetrack. The smaller, northern accumulation remains unpenetrated. Both accumulations are located at approximately 16,500' TVDss. The wells were tied back to the Shell-BP Na Kika host, located in MC474 in 6,340 feet of water about 27 miles from the wells (Fig.1). The host incorporates the concept of a dispersed subsea development tied- back to a centrally located semi-submersible shaped "Na Kika host" facility. The host and subsea structure is designed for other tie-backs to enable furtherdevelopment in the field. The production from both wells were commingled through a single 8″ flowline and controlled by a network of subsea umbilicals. Both wells came on stream June 2004 at rates exceeding expectations. Application of internal plastic coating to the bore of the production tubing provided a more uniform surface thereby lowering the frictional pressure drop. This contributed to the higher production rates from these well.
Artificial lift could significantly increase ultimate recovery from deepwater Gulf of Mexico (GOM) reservoirs, but the extreme application will present unique challenges to conventional artificial lift designs. This paper presents an exploration of feasibility and operability issues for both gaslift and Electric Submersible Pump (ESP) usage in direct vertical access wells in the deepwater GOM. System and equipment considerations for gaslift and ESP design specific to the typical deepwater GOM application are discussed. Either system will work in this application, but they will both push current technology to the limit. The incremental recovery associated with either system is shown to be largely a function of the producing gas-liquid ratio. A description of the creation and interpretation of outflow curves for the two types of artificial lift is also included. Outflow curves are an important element in the simulation of well deliverability and reservoir performance over time. Proper use of these curves and an understanding of the curve limits are necessary to perform a valid simulation. P. 43
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