«Paper #2-11 SUBSEA DRILLING, WELL OPERATIONS AND COMPLETIONS Prepared by the Offshore Operations Subgroup of the Operations & Environment Task Group ...»
Jack-Up Rigs. Jack-up drilling rigs are similar to a drilling barge because the complete drilling rig is built on a floating hull that must be moved between locations with tug boats. Jack-ups are the most common offshore bottom-supported type of drilling rig. Once on location, a jack-up rig is raised above the water on legs that extend to the seafloor for support. Jack-ups can operate in open water or can be designed to move over and drill though conductor pipes in a production platform. Jack-up rigs come with various leg lengths and depth capabilities (based on load capacity and power ratings). They can be operated in shallow waters and moderate water depths up to about 450 ft.
Semi-Submersible Rig. Semi-submersible drilling rigs are the most common type of offshore floating drilling rigs and can operate in deep water and usually move from location to location under their own power. They partially flood their pontoons for achieving the desired height above the water and to establish stability. “Semis” as they are called may be held in place over the location by mooring lines attached to seafloor anchors or may be held in place by adjustable thrusters (propellers) which are rotated to hold the vessel over the desired location (called dynamically positioned).
Drillships. Drillships are large ships designed for offshore drilling operations and can operate in deepwater. They are built on traditional ship hulls such as used for supertankers and cargo ships and move from location to location under their own power. Drillships can be quite large with many being 800 ft in length and over 100 ft in width. Drillships are not as stable in rough seas as semi-submersibles but have the advantage of having significantly more storage capacity. Modern deepwater drillships use the dynamic positioning system (as mentioned above for semisubmersibles) for maintaining their position over the drilling location. Because of their large sizes, drillships can work for extended periods without the need for constant resupply. Drillships operate at higher cruising speeds (between drillsite locations) than semi-submersibles.
B. Offshore Drilling and Production Platforms For the development of a reservoir after commercially viable natural gas or petroleum deposits are located, a permanent production platform may be constructed or the wells may be completed subsurface. Large permanent production platforms are extremely expensive to build and operate.
There are a number of different types of permanent offshore platforms, as shown in Figure 3.
Figure 3. Varieties of offshore production platforms (NOAA, 2010).
C. Subsea Completions
A subsea completion is one in which the producing well does not include a vertical conduit from the wellhead back to a fixed access structure. A subsea well typically has a production tree to which a flowline is connected allowing production to another structure, a floating production vessel, or occasionally back to a shore-based facility. Subsea completions may be used in deep water as well as shallow water and may be of any pressure and temperature rating including high-pressure, high-temperature (HPHT)1 ratings. Subsea completions consist of a production tree sitting on the ocean floor, an upper completion connecting the production tree to the lower completion and the lower completion which is installed across the producing intervals.
Hansen and Rickey (1995) reviewed the history and types of subsea production systems and Bernt (2004) provided a more recent example of actual implementations.
HPHT environment means when one or more of the following well conditions exist: (1) pressure rating greater than 15,000 psig or (2) temperature rating greater than 350 degrees Fahrenheit.
The first subsea well was installed at West Cameron 192 in 55 ft. water in the Gulf of Mexico (GOM) in 1961. Others soon followed but a significant departure was introduced in 1993 with the advent of the first horizontal tree (Skeels et al., 1993). That allowed access to the wellbore for workovers and interventions without having to disturb the tree and associated flowlines, service lines, or control umbilicals. Developments of subsea and other equipment for higher pressures and temperatures continued as operators progressed to drill deeper wells with more stressful physical conditions. The next major advance in subsea trees came in 2007 with the introduction of an all-electric tree (Bouquier et al., 2007).
Subsea completions typically contain an upper completion, a lower completion, and a production tree. Advances in upper and lower completions followed normal developments in materials, pressure, and temperature ratings (Maldonado et al., 2006). However, significant advancements in the area of gravel packing the lower completion occurred with the introduction of one-trip installation of multiple-zone systems. The latter advancement reduced operational costs and led to the capability to develop more stratified reservoirs with one-trip and single system (Burger et al., 2010). Additional details are explained below.
Production Tree. The production trees are typically available in traditional vertical trees and horizontal trees. Those are further characterized by their mode of operation (electric versus hydraulic) and the number and types of penetrations through the tree to control subsurface equipment and hydrocarbon production.
Upper Completion. The upper completion consists of production tubing from the tree to the subsurface safety valve (SSSV) and then production tubing down to the production packer installed in the production casing. The types of SSSVs vary by their method of installation. For normal wells, the typical mode is within the tubing and installed with the completion. If situations warrant, the SSSV can be installed on wireline in a specially prepared profile inside the tubing string. Other variations of SSSVs include the method of operation (hydraulic versus electric), and various types depending on methods of construction (opening method, sealing mechanism, etc.). The production tubing varies by metallurgy which is dictated by the combination of well loads and fluid environment. The production packer varies by the desired method of retrieval. Permanent packers must be drilled out to remove them from the wellbore while retrievable packers may be retrieved (usually with a dedicated pulling tool). Other variations of the packer include the connection to the tubing string (ratch-latch with seal assembly, tubing connection, or polished bore receptacle) and the packer/slip geometry. Most manufacturers offer an HPHT package if required.
Lower Completion. The lower completion consists of a gravel-pack packer, sand control screens, and a lower sump packer all connected together by production tubing. The gravel-pack packer is installed above the screens and serves to anchor the lower completion inside the production casing. Various types of packers are available depending on the method of gravel packing the well and the desired release mechanism. The sand control screens and the accompanying gravel pack or frac pack vary with the formation types and desired productive interval placement. Screens may be of various types including wire mesh; wire wrapped, and pre-packed screens. Expandable sand screens may also be installed to maximize the remaining inside diameter of the screen base pipe.
BASIC WELL CONSTRUCTIONA. Sequence of Well Construction Operations The sequence of drilling operations (Fig. 4) involves drilling a large diameter hole first and running a large diameter conductor casing then drilling progressively smaller hole sizes as downhole pressures increase. As drilling progresses, successively smaller and stronger casings are installed (if they extend back to surface) or liners, rather than casings, if the liner extends back to the previous casing.
For drilling from permanent installations and for drilling from a jack-up rig, a conductor pipe is installed and secured to the seabed for circulation of the drilling fluid to remove cuttings. For those applications the blowout preventers (BOPs) are installed just below the drilling rig.
For deepwater operations after drilling the first casing interval, a drilling riser is attached to the wellhead and used to circulate drilling fluid to remove cuttings. The BOPs and riser are installed at the seafloor onto a wellhead system. The wellhead system is run while attached to the first string of casing run inside a large diameter conductor pipe that accommodates the jetting or drilling action. The first string of casing is usually conducted as “riserless drilling”, namely, with no riser connection and therefore with fluid and cuttings exhausted to the seafloor. Figure 5 shows the riser and subsea BOP for a floating semi-submersible rig.
Figure 4. Simplified view of drilling and oil or gas well (Nergaard, 2005).
For each drilled interval, the drill bit is rotated either from a surface-located mechanical motor or by a downhole mud motor. The hole is drilled into subsurface formations as high-pressure drilling fluid (mud) is pumped down the inside of the drill string to circulate downward and lift the drilling cuttings upward through the casing annulus. Once the drilling fluid and cuttings reach the drilling rig, the cuttings are removed by vibrating shale shakers and the drilling fluid is processed and chemically treated to sustain continuous recirculation. Efficient processing and proper treatment are important because they limit the quantity of drilling fluid required and the volume of waste generated.
Each depth interval of the well is evaluated and designed in the planning stages and re-evaluated for modification during the wellbore construction process. The length of each interval, the drilling fluid density, the drilling assembly, the casing to be run, the type and quantity of cement to be used, the type of drilling fluid used and many other processes are decided based on the anticipated subsurface pressures, equipment limitations, actual wellbore conditions and other factors. The number and type of casing strings and the depth for each string is determined by evaluating each interval for the subsurface rock stress and pore pressure, the strength of the casing that will be run, anticipated hole problems, required hole size at total depth, and the type of completion to be used. Figure 6 illustrates the number and sizes of casing strings that might be needed for a deepwater Gulf of Mexico well.
Well control (which is treated in a separate topic paper) is established by having barriers to prevent unwanted influxes of formation fluids into the wellbore. The most basic barrier is to use a drilling fluid of sufficient density that its hydrostatic pressure will prevent the influx of subsurface fluids. Drilling fluid densities typically range from that of seawater to more than 2 times that of seawater. However, if the drilling fluid is too heavy or the exposed formations are too weak, a fracture in the rock may occur and circulation of drilling fluid may become impaired as fluid leaks from the wellbore into the underground formation.
As the water depth increases, the mudweight operating window at shallow depths gets progressively smaller such that numerous shallow casing strings may be needed unless special drilling practices are employed (such as riserless drilling).
B. Circulation System
Drilling fluid circulation (Fig. 7) begins at the mud tanks which hold a large volume of fluid to allow the mud pumps to draw and pump drilling mud under high pressure into the inside of the drill string where the fluid is circulated downhole.
The fluid sent downhole serves to power downhole equipment and to provide hydraulic power to accomplish removal of drill cuttings to the surface. Fluid and drill cuttings are separated at the surface by vibrating shale shakers which use fine mesh screens to remove drill cuttings from the drilling fluid. Additional processing of the fluid includes gas removal (degasser), supplemental solids separation (desanders, desilters, and centrifuges), and chemical treatment to maintain the desired fluid properties. Depending on the applicable regulatory permits, the drill cuttings may be discharged to the ocean water, collected for transport to land for disposal or made into a slurry which can be injected into a disposal well.
To identify potentially productive formations within the geological horizons being drilled, a variety of techniques are used. The most basic technique is called mud logging where the drill cuttings are evaluated for formation type and the presence of any hydrocarbons. More sophisticated techniques are called well logging where special electronic tools are run either in the drill string or on a wireline normally at selected casing points to evaluate key rock properties. Also, formation pressures can be measured or core samples can be obtained with specialized drilling tools or wireline logs.
Figure 8. Completed well (Oil in Israel, 2009).
After being drilled, the offshore well must be completed with tubing and a variety of other equipment to allow the oil or gas to be produced. Completion work may involve installing a slotted liner or perforated casing adjacent to the productive formations then installing packers and tubing to conduct the oil or gas flow to the surface. Figure 8 is a schematic example of a completed subsea well.
D. Riserless Drilling
When an offshore deepwater well is spudded, and prior to the installation of the riser, seawater and sweeps are used to jet or drill the structural and conductor casings. Effective deepwater well designs require that the first casing string is positioned deep enough that the formation has sufficient mechanical strength to withstand the formation pressures anticipated in the next (deeper) interval. Due