The challenge of maintaining deepwater wells
Technology changes for deepwater wells improve process, but they also add complexity.
In the last 25 years there has been a rapid advance into deep and ultra-deep depths facilitated by the industry’s development of new technologies. Such production is primarily from subsea wells; that is, wells completed on the seafloor. Today, operators are producing from almost 10,000-foot depths in the Gulf of Mexico.
The technologies that make such an operation technically feasible-and economical-are a huge leap from the offshore industry’s early days 120 years ago when offshore drilling was done from piers connected to land. The fundamentals haven’t changed much, but the technologies tied to the drilling function have improved dramatically over the years.
Drilling starts with a large diameter hole that is drilled until the formation at the well bottom is near collapse, or the drilling fluid starts leaking out. At that point, a string of pipe, called casing, is lowered into the hole and cement is forced from the bottom, up the annulus between the pipe and the rock.
A smaller drill bit is then used to drill deeper from the bottom of the previous casing. This smaller hole is drilled as far a possible. Then another, still smaller casing, is lowered inside and cemented. This continues until the reservoir is reached. For land and shallow water wells, there are usually four or five casing strings. (See Figure 1).
In deeper water, the number of casing strings may get up to nine or even more. When that happens, some of the casing strings start at the bottom of the last casing rather than from the top of the well. Shorter casing strings are called liners. The last casing string, the production casing, penetrates the reservoir.
The next step is well completion. Part of the well completion operation is to perforate, or blast holes through the production casing. Fluids from the reservoir flow through these holes into the well. The perforation also penetrates out into the reservoir rock, creating cracks that serve as flow paths into the well.
Prior to the perforation operation, a production tree, often called a "Christmas Tree," is clamped to the wellhead at the top of the uppermost casing string. This creates a pressure-sealed path from the top of the well to the production zone at the bottom. The tree is generally rather complex but basically, it is an arrangement of ports and valves providing access into the well.
The last string of pipe, the production tubing is then lowered through the tree all the way to the bottom, creating a flow path for production. It also creates an annulus, between the tubing and the production casing. Production comes up the tubing. Gas and other fluids can be pumped down the annulus for various purposes. Transfer of these fluids from the annulus into the tubing, or out into the reservoir, is controlled by valves that are part of the completion, as described next.
Elements of a downhole completion
The downhole completion generally refers to everything in the hole, below the production tree. The downhole configuration varies widely depending on temperature, pressure, oil viscosity, oil/gas/water ratios, number of production zones, etc. Following are just a few of the elements that might be in a downhole completion.
- Surface-controlled, subsurface safety valve (SCSSV): Usually a few hundred feet below the mudline, the valve is held open by hydraulic pressure from the surface. Loss of the hydraulic pressure, due to an accident for example, allows a spring to close the valve, shutting in the well completely.
- Sliding sleeve controls communication between the tubing and the annulus. It may be used to admit gas into the tubing to assist in lifting oil from the hole.
- Formation isolation valve is used to shut off production from a production zone, for example when that zone begins producing water instead of oil.
- Downhole gauges are electronic or fiber optic connected sensors that allow monitoring of downhole pressure, temperature, flow rate, etc.
- Gravel pack is intended to stop the flow of sand coming from the reservoir. Sand in the production stream damages pipe and equipment.
- Submersible pump is hydraulically or electrically powered, adding pressure when the formation pressure is too low to push product to the surface.
Need for well intervention
Following drilling and completion, a production well comes on stream, that is it starts production. Ideally, production flows, undiminished for years. Of course, that never happens. Instead, production changes. Perhaps the water cut increases and oil production decreases or even stops. Perhaps pressure and flow rates decline faster than expected. Sand content in the flow may increase, eroding piping and pumps. In each case, a diagnosis must be carried out to determine the cause and possible actions that may restore production, or at least maximize it.
Whatever the action, it is called a workover or intervention. The simplest might be pumping acid into the reservoir to dissolve chemicals that are clogging the flow paths in the rock; or pumping high-pressure water to extend the cracks and increase the flow rate. But there is a myriad of other problems that can require intervention—sand, scale or wax collecting in the well; one of the many mechanical valves or gauges failing; tubing corroding and leaking; etc. Some examples are given in Table 1.
So what is required to perform a well intervention on land or shallow water?
- Injection: The production tree on a land well sits out in the open at the end of an access road. It usually has a number of hand cranks for valves that shut in production and others for access to the annulus for pumping gas or fluids down the hole. For an injection intervention, a truck hooks up lines to the annulus port on the tree and pumps in the injection fluid. The fluid can be for stimulating the reservoir to increase production. It also might be an inhibitor to reduce corrosion of downhole components or of the tubing. Gas can be injected to mix with and lighten product in the well so it will flow faster.
- Wireline: The next level of intervention is necessary when the problem is accumulation of sand, scale or wax. In such cases, lowering a tool on the end of a wire or electric line may solve the problem. The tool may be powered, like a mill grinder or pump. This is called a wireline workover and utilizes a lubricator, a long tube through which the wire passes. The lubricator contains the well pressure, collecting the small amount of product that may flow past the wire. Wireline tools can do a range of repairs, including replacing some downhole components. A wireline workover would be categorized as light.
- Coiled tubing: Well problems often cannot be solved without circulation to remove unwanted fluids or contaminants. A means of quickly creating a flow path to the well bottom is called coiled tubing. Coiled tubing is continuous metal pipe, between 1-1/8 and 1-½ in. in diameter that is wrapped around a large reel. An injector straightens and pushes the small tubing into the well, inside the production tubing. The coiled tubing reel, injector, pump and controls together comprise a coiled tubing unit. They exist in a wide range of sizes and capabilities to meet a range of needs including pumping stimulants, cement, anti-corrosion material, etc.
- Workover rig: Some problems are beyond the capabilities of wireline and coiled tubing. For example, corroded tubing must sometimes be pulled out of the hole and replaced. In that case, a workover rig, similar to the original drilling rig but smaller, is required. It removes part of the tree and replaces it with a workover BOP. To accomplish this, the well is filled with kill weight fluid, fluid so heavy that it balances the formation pressure at the bottom of the hole preventing product influx. The rig then pulls out the tubing and runs in a new one. Depending on completion design, a workover rig may also be required to replace some of the downhole components. An operation requiring a workover rig would be categorized as heavy.
Wells on shallow water platforms, that is in water depths to about 1000 feet, are very similar to land wells.
The platforms stand on the seafloor and don’t move. The production wells are inside conductors that extend from the seafloor up to the platform deck. A conductor is basically an extension of the well bore from the seafloor to the platform deck. Conductors are stabilized by the platform structure. Each well has a production tree on the deck, much like on land.
One difference is that offshore, the trees are closely spaced to minimize the required platform size. The drilling derrick and the workover derrick are supported on a deck above the trees. To drill or perform a workover, the derrick is skidded over the particular well slot. Since platforms are expensive to build and install, each one produces from a large underground area. This is achieved by directional drilling and extended reach.
Well maintenance is relatively efficient on an offshore platform. A workover rig is generally kept on the platform, readily available as needed. There may also be a coiled tubing unit.
As offshore reservoirs were discovered in water depths beyond those feasible for bottom founded platforms, floating platforms were developed. There have been two types that accommodate surface production trees, the tension leg platform, (TLP), and the Spar. Both have been used extensively in the Gulf of Mexico. TLPs are economically limited to about 4,500 feet of water. Spars have been chosen for fields over a range of water depths extending to 8,300 feet. Both concepts were developed to have minimal heave or vertical motion.
Low vertical motion permits use of well conductors, now called production risers, which extend up from each well at the seafloor to a tree on the platform deck. These risers resemble conductors on bottom-founded platforms. But instead of being rigidly attached to the platform, risers are held up by hydraulic-pneumatic tensioners that accommodate the small amount of platform heave. With the production trees on the platform deck, drilling and workover operations on TLPs and spars are little different from bottom-founded platforms.
TLPs and spars are expensive, requiring large fields to be economical. They also have very little storage capacity, necessitating pipelines and reliable shuttle tanker visits for export. Small and remote deepwater development opportunities often do not economically support construction of a TLP or Spar.
In the mid-eighties, some smaller companies started to try a new development concept with subsea completions: floating production storage and offloading units (FPSO). The kind of FPSOs shown in Figure 2 have storage but no drilling or workover capability. Most of the FPSO developments were based on converted tankers making them fast and cheap to get on stream. The production wells are completed on the seafloor with, as they were originally called, wet trees. Flowlines on the seafloor connect the trees to risers that bring product up to the FPSO.
Some of the subsea developments were tiebacks to existing platforms. Small fields that could not support the cost of a new platform could be developed subsea if they were within 30 or 40 miles, or more. One deepwater, subsea gas field tieback is 90 miles from its shallow water platform.
Maintenance of the seafloor equipment depends on access with remotely operated vehicles, ROVs. The subsea trees are designed in conjunction with ROV tools that facilitate removal and replacement of critical components.
Drilling and maintenance of subsea wells is performed by a mobile offshore drilling unit (MODU). The MODUs also can do the downhole maintenance or well intervention. However, this is expensive due to high MODU day rates. Because of the new subsea technology and the high well maintenance cost, major oil companies were leery of the FPSO/subsea completion approach. The early FPSO and subsea developments were mostly by independents.
Between 1990 and 2010, there was a dramatic increase in the number of subsea developments. Project economics was the driver. Reservoirs being discovered in deep and ultra-deep water were very large and very prolific, meaning that individual wells were highly productive. In addition, subsea manufacturers and the service companies saw opportunity and began to invest heavily in new technology.
Subsea equipment suppliers advanced their tree designs to incorporate greater ROV serviceability. They also put computers in trees, greatly expanding control and monitoring from (sometimes very) remote operators.
Offshore service boat operators started to develop specialized, single hull vessels with increased well service capabilities. This began to bring down the cost of well intervention over use of MODUs.
A parallel advance occurred in subsea umbilicals, which is the communication link between the platform and the subsea equipment. It comprises a bundle of conduits carrying electronic data, electrical and hydraulic power and fluids for reservoir stimulation, corrosion inhibition, gas lift, etc. Each umbilical is custom-designed for the cluster of wells it serves. A router on the seafloor at the end of the umbilical distributes the contents to the individual trees, or clusters of trees.
With these technology advances, major operators gained confidence that they would be able to monitor and maintain subsea installations without costly interruptions in production.
The requirements for intervention in subsea wells are basically the same as described above for land and shallow water wells. The challenge is doing it under thousands of feet of water. The newest MODUs that drill and complete deepwater, subsea wells are also equipped to perform the entire range of workovers from wireline to full bore repairs like tubing replacement. Over recent years, many of those capabilities have become available on smaller boats.
Like deepwater MODUs, all the new intervention boats have the capability to hold location above a well by dynamic positioning. That means they have computer-controlled thrusters that automatically resist the varying environmental forces.
The basic capability of intervention boats is wireline. A wireline system can land a pressure control package and lubricator on top of the subsea tree. Tools contained in the package are lowered into the well to perform many of the operations listed in the table. The capabilities often include motors driving pumps or mills. There may also be sensors on the tool providing real-time measurements to the operator.
Some wireline units are relatively light and compact. Recently, mobile wireline units have been developed that can be temporarily placed on general-purpose service boats of opportunity. This innovation enhances light intervention availability and reduces cost.
The next level of capability is a coiled tubing unit (CTU). The CTU requires a pressure control package that incorporates a subsea injector to push the tubing into the well. Fluids, including kill fluid or cement, can then be pumped into the well where needed. This capability is currently limited due to the high weight of tubing needed to reach deepwater wells.
Other problems are fatigue sensitivity of the metal tubing and flow rate limitations due to the small diameter. A promising new development uses a 3-inch carbon fiber reinforced pipe that is about neutrally buoyant. It has better fatigue resistance than metal-coiled tubing and permits higher flow rates.
A few of the larger intervention vessels can deploy a small, workover riser through which the coiled tubing is inserted. The annulus between the tubing and the riser permits return circulation from the well. Many more operations are possible when there is return flow. For example, some CTUs can drill small, openhole sidetracks into new areas of the reservoir.
The heavy intervention operations in Table 1 usually require mobilization of a MODU. Such a vessel would have the capability of landing a workover BOP on top of the subsea tree for repairs such as replacing major downhole components including the tubing or submersible pump. Other capabilities include drilling, casing and completing a sidetrack into a new part of the reservoir, or even removing and retrieving the tree for major repairs.
Subsea intervention economics
By the end of 2014, there were more than 5,000 subsea wells on stream in four major areas—the North Sea, West Africa, Brazil and the Gulf of Mexico. There still are only a limited number of intervention vessels to service them, although this market has been attracting many new players and considerable investment.
But subsea well operators are faced with a tight intervention vessel market or use of expensive MODUs. The consequential lower intervention frequency on subsea wells means that reservoir depletion is less than on offshore platform and land fields where well stimulation is more routine. Until the drop in crude oil prices, the large reservoirs and high well productivity of deepwater fields have kept their economics attractive.
The full effect of cheap oil on deepwater production is yet to be seen. Operators are cutting capital investment but remain committed to replacing production. One analysis suggests that the cost of adding recoverable reserves by intervention in producing fields is cheaper than by development of new fields. Further, it is likely that drilling companies with idle MODUs will offer them at competitive prices for intervention work, further enhancing intervention economics.
Terry N. Gardner, PhD, a senior associate with EKTInteractive, Inc. in Houston, is a mechanical engineer who spent over 35 years with Exxon and BP working to advance deepwater drilling and production technology. He received a PhD from UCLA and an MS and BME from Cornell University in Engineering Mechanics.
Original content can be found at Control Engineering.