2 Oilfield Review

Subsea Solutions

Alan ChristieAshley KishinoRosharon, Texas, USA

John CrombTexaco Worldwide Exploration and ProductionHouston, Texas

Rodney HensleyBP Amoco CorporationHouston, Texas

Ewan KentBrian McBeathHamish StewartAlain VidalAberdeen, Scotland

Leo KootShellSarawak, Malaysia

For help in preparation of this article, thanks to RobertBrown, John Kerr and Keith Sargeant, SchlumbergerReservoir Evaluation, Aberdeen, Scotland; and MichaelFrugé, Andy Hill and Frank Mitton, Schlumberger ReservoirEvaluation, Houston, Texas, USA; EverGreen, E-Z Tree, IRIS (Intelligent Remote ImplementationSystem) and SenTREE are marks of Schlumberger.

All wells are not created equal. Subsea wells, which spring from

the ocean floor yet never see the light of day, have a life-style all

their own. Constructing these wells and keeping them flowing and

productive require heroic efforts that are now paying off.

1. Brandt W, Dang AS, Magne E, Crowley D, Houston K,Rennie A, Hodder M, Stringer R, Juiniti R, Ohara S,Rushton S: “Deepening the Search for OffshoreHydrocarbons,” Oilfield Review 10, no. 1 (Spring 1998): 2-21.

Winter 1999/2000 3

The mysteries and challenges of the world underthe sea have long enticed adventurers andexplorers. For thousands of years, people havespeculated on the existence of underwater civi-lizations and dreamed of discovering lost cities ordeveloping ways to live and work under the sea.

Underwater cities remain a fantastic vision,but some aspects of everyday industry do tran-spire at the bottom of the sea: early communica-tions cables crossed the ocean bottoms; researchdevices monitor properties of the earth and sea;and military surveillance equipment tracks suspi-cious activity—all as extensions of processesthat also take place on land.

Similarly, the oil and gas industry hasextended its early exploration and productionoperations with land-based rigs, wellheads andpipelines to tap the richness of the volume ofearth covered by ocean. This evolution from landto sea has occurred over the past century, start-ing in 1897 with the first derrick placed atop awharf on the California (USA) coast (right).1

Seagoing drilling equipment followed, with off-shore platforms, semisubmersible and jackupdrilling rigs, and dynamically positioned drill-ships. From one point on a fixed platform or float-ing rig, wells could be drilled in multipledirections to reach more of the reservoir.

As offshore technologies advanced to conquerincreasingly hostile and challenging environ-ments, offshore drilling moved forward in twomajor directions: First, and predictably, wellswere drilled at greater water depths every year,until the current water-depth record wasachieved—6077 ft [1852 m] for a producing wellin the Roncador field, offshore Brazil.2 Drilling forexploratory purposes, without actually producing,has been accomplished at the record depth of9050 ft [2777 m] for Petrobras offshore Brazil.OtherGulf of Mexico leases awaiting exploration reachwater depths of more than 10,000 ft [3050 m].

2. Bradbury J: “Brazilian Boost,” Deepwater Technology,Supplement to Petroleum Engineer International 72, no. 5(May 1999): 17, 19, 21.Deepwater has different working definitions. One defini-tion of deep is 2000 ft in hostile environments, 3000 ft[1100 m] otherwise. Another is deep for more than 400 m[1312 ft] and ultradeep at more than 1500 m [4922 ft].

> A time line of offshore operations.

Offshore drilling

1897 Derrick placed atop wharf 250 ft [76 m] from shore

1911 First drilling platform

1925 First artificial island for drilling

1932 First well drilled from independent platform

1953 First mobile submersible rigs

1956 Drill to 600-ft [183-m] water depth

1966 First jackup

Deepwater

1970 Guideline drilling in 1497-ft [456-m] water depth

1971 First dynamically positioned oil drillship

1987 Water depth drilling record of 7520 ft [2292 m]

1994 Water depth oil production record of 3370 ft [1027 m]

1996 Water depth oil production record of 5607 ft [1709 m]

Subsea

1961 First subsea Christmas tree

1973 First multiwell subsea template

1991 Record subsea tieback to 30 miles [48 km]

1992 First horizontal tree

1996 Record tieback to 68 miles [109 km]

1997 1000 subsea wells completed2000 Water depth

drilling record of 9050 ft [2777 m]

In a second direction, well-completion equip-ment has entered the water. Wellheads on theseafloor, in what is called a subsea completion,connect to flowlines that transport oil and gas tothe surface (above left). With multiple points ofaccess, more of the reservoir can be reachedthan through extended-reach wells, so the reser-voir volume can be exploited more thoroughly. Inaddition, field development costs can be greatlyreduced through use of a common central facility.

The earliest subsea wells were completedfrom semisubmersible drilling rigs with the help ofdivers who directed the equipment into place andopened the valves. Today, subsea completions canbe too deep for divers, so the production equip-ment is monitored and manipulated by remotelyoperated vehicles (ROVs). The simple wellheadand pipeline arrangement has expanded toencompass multiple wellheads connected to amanifold by flowlines, then to a floating produc-

tion system, neighboring platform or shore-basedfacility (above right). Groups of manifolds con-nected to central subsea hubs maximize areal cov-erage of the reservoir. The tieback distancebetween the subsea completion and its platformconnection has increased from a few hundred feetor meters to a record 68 miles [109 km], held bythe Mensa field in the Gulf of Mexico.3

4 Oilfield Review

> A subsea production tree, with flowline connecting to a surface facility.

> Multiple trees. A group of five subsea production trees is linked to a manifold, where flow is collected at a single station before continuing to surface. A second group of five subsea water-injection wellsis in the background.

Winter 1999/2000 5

More and more of the operations originallyperformed at surface are moving to the seafloor.Today’s subsea technology covers a wide rangeof equipment and activities: guidewires for low-ering equipment to the seafloor; Christmas, orproduction, trees; blowout preventers (BOPs);intervention and test trees; manifolds; templates;ROVs; flowlines; risers; control systems; electri-cal power distribution systems; fluid pumpingand metering; and water separation and reinjec-tion. One futuristic vision even depicts a seafloordrilling rig.4

The first subsea production tree was installedin 1961 in a Shell well in the Gulf of Mexico.5

Within 36 years, 1000 wells had been completedsubsea. Industry champions predict that complet-ing the next 1000 will take only another fiveyears, and that expansion will continue at around10% per year for the next 20 years.

In some areas, such as the Gulf of Mexico andoffshore Brazil, expansion will require pushingthe frontiers of depth-limited technology. Onlytwo wells in the world have been completed sub-sea at greater than a 5000-ft [1524-m] waterdepth. Increases in the number of subsea com-pletions are projected for all depths, but the moststriking will be for the ultradeep (above).6

In other areas, the North Sea in particular,growth is evident in the increasing number ofsubsea completions per project. Norsk Hydro isplanning to develop the Troll field with more than100 subsea wells tied back to a floating produc-tion system.

The subsea environment poses a set of tech-nological challenges unlike anything that the sur-face can present, and more than can be coveredhere. This article reviews the task of completinga subsea well and explains the workings of theequipment that controls access to the wellthrough every stage of its existence, from explo-ration, appraisal and completion to interventionand abandonment.

Why Subsea?Describing the full process behind choosing onedeepwater development strategy over another isalso beyond the scope of this article, but a briefoverview will help set the background. As in theplanning of any asset development, the decision-making process attempts to maximize assetvalue and minimize costs without compromisingsafety and reliability. The cost analysis focuseson capital expenditures and operating expenses,and also includes risk, or the potential costs ofunforeseen events.

The conditions driving these costs are numer-ous and interrelated, and include all the reser-voir-related factors usually considered inland-based development decisions, plus thosearising from the complexities of the offshoreenvironment. An abbreviated list includes exist-ing infrastructure, water depth, weather and cur-rents, seabed conditions, cost of constructionand decommissioning of permanent structures,time to first production, equipment reliability,well accessibility for future monitoring or inter-vention, and flow assurance—the ability to keepfluids flowing in the lines.

Certain of these conditions pose awesomechallenges for any offshore development, andpresent strong arguments for subsea completioninstead of or combined with other options suchas semisubmersibles, tension-leg platforms, dry-tree units, and floating production, storage and

offloading systems (FPSOs). Distance from infras-tructure is a key determinant in opting for a sub-sea completion. Wells drilled close enough toexisting production platforms can be completedsubsea and tied back to the platform. The tiebackdistance is constrained by flow continuity,seafloor stability and currents. With some fixed-platform capital expenditures measured in billions of dollars, maximizing reservoir accessthrough additional subsea wells can increaseproduction while keeping capital and operatingcosts down.

Wells whose produced fluids will be handledby an FPSO vessel are also natural candidatesfor subsea completions, and not only because ofreduced time to production. Often these arewells in locations where water depth andweather make more permanent structuresimpractical or uneconomical. Other options inthese environments are either the dry-tree unit,sometimes called a spar, which is a buoyant ver-tical cylinder, or the tension-leg platform—afloating structure held in place by vertical, ten-sioned tendons connected to the seafloor bypile-secured templates. Both the dry-tree unitand the tension-leg platform support platformfacilities and are anchored to the seafloor. Thelatter techniques have been applied withoutsubsea completions at depths reaching about4500 ft [1372 m], but deeper than that the solu-tion has called for a subsea completion in con-junction with the floating systems.

50 150 250 350 450 600 800 1000 2000 3000

Water depth, m

0

100

200

300

400

500

600

700

OperationalPlanned

Num

ber o

f sub

sea

com

plet

ions

> Number of subsea wells, both operational and planned by 2003, by water depth.

3. Sasanow S: “Mensa Calls for a Meeting of the Minds,”Offshore Engineer 24, no. 7 (July 1997): 20-21.

4. Thomas M and Hayes D: “Delving Deeper,” DeepwaterTechnology, Supplement to Petroleum EngineerInternational 72, no. 5 (May 1999): 32-33, 35-37, 39.

5. Greenberg J: “Global Subsea Well Production Will Double By Year 2002,” Offshore 57, no. 12(December 1997): 58, 60, 80.A Christmas tree is the assembly of casing and tubingheads, valves and chokes that control flow out of a well.

6. Thomas M: “Subsea the Key,” Deepwater Technology,Supplement to Petroleum Engineer International 72, no. 5 (May 1999): 46, 47, 49, 50, 53.

At the water depths in question, runninghydrocarbons through flowlines, valves andpipelines is not an effortless task. The low tem-peratures and high pressures can cause precipi-tation of solids that reduce or completely blockflow. Precipitation of asphaltenes and paraffins isa problem for some reservoir compositions, usu-ally requiring intervention at some stage of welllife. Scale deposits can also impede flow, andneed to be prevented or removed.7 The formationof solid gas hydrates can cause blockages intubulars and flowlines, especially when a water-gas mixture cools while flowing through a long tieback. Prevention techniques includeheating the pipes, separating the gas and waterbefore flowing, and injecting hydrate-formationinhibitors.8 Corrosion is another foe of flow conti-nuity, and can occur when seawater comes incontact with electrically charged pipes.

Access to the well for any tests, intervention,workover or additional data acquisition is a keyconsideration. Traditionally, operators haveselected platform-style solutions when thedevelopment requires postcompletion wellaccess. Platforms house Christmas trees andwell-control equipment on the surface, givingeasier access to introduce tools and modify welloperations. To perform these functions on subseawells requires a vessel or rig, and sometimes amarine riser—a large tube that connects thesubsea well to the vessel and contains thedrillpipe, drilling fluid and rising borehole fluids—and planning for their availability whenthe time comes.

All of this adds up to significant cost. In manycases, the subsea production tree must beremoved. Reconnecting to many subsea wells toperform workovers and recompletions can alsorequire a specially designed intervention system

to control the well and allow other tools to passthrough it down to the level of the reservoir. Thedevelopment of the completion test tree is nowenhancing the accessibility of subsea wells,allowing reliable well control for any imaginableintervention. A full discussion follows in latersections of this article.

Equipment reliability is a major concern for anysubsea installation. Once equipment is attached tothe seafloor, it is expected to remain there for thelife of the well. Some operators remain uncon-vinced about the suitability and reliability of sub-sea systems in ultradeepwater developments.However, more and more operators are gainingconfidence in subsea practice as contractors pro-vide innovative and tested solutions.

Equipment Much of the specialized equipment for subseainstallations is designed, manufactured, posi-tioned and connected by engineering, construc-tion and manufacturing companies. ABB VetcoGray, FMC, Cameron, Kvaerner, Oceaneering,Brown & Root/Rockwater, McDermott, Framoand Coflexip Stena are among the companiesthat supply most of the BOPs, wellheads, tem-plates, production trees, production control sys-tems, tubing hangers, flowlines, umbilicals,ROVs, multiphase meters and pumps, separatorsand power generators. The largest structures,such as manifolds, can weigh 75 tons or more,and can be constructed and transported in modu-lar form and assembled at the seafloor location.

In addition, oilfield service companies andother groups provide special tools and servicesfor the subsea environment. Baker Hughes,Halliburton, Expro, Schlumberger and othershave developed solutions to crucial wellbore-related problems.

One of the key concerns in constructing andoperating a subsea well is maintaining well con-trol at all times. Drilling, completion and subse-quent servicing of subsea wells are typicallyperformed from one of two types of vessel: afloating system that is tethered or anchored tothe seafloor; or one that maintains location overthe well with a dynamic positioning system. Inboth cases, it is critical that the vessel remain inthe proper position, or “on station.” The positioncan be described as the area inside two concen-tric circles centered over the well location on theseafloor. The inner circle represents the limit ofthe preferred zone, and the outer circle repre-sents the maximum acceptable limit before dam-age occurs. The vessel activates thrusters topropel the vessel back to the desired location ifcurrents or other conditions such as weatherhave caused it to move off station, all while continuing the drilling, testing, completion orwell intervention.

However, under extreme conditions, thedynamic positioning system may be unable toremain on station or a situation may arise thatcould endanger the vessel. System problemscould include the failure of the thruster system orloss of some anchoring lines, causing the vesselto drift off station. Other situations could includesevere weather or collisions with icebergs orother vessels. Under such conditions, the dynam-ically positioned vessel would drive off station.

All these cases would require disconnectingthe landing string and riser from the well. Oncethe decision to disconnect from the well is made,industry best practices for operation in deepwater with dynamically positioned vesselsrequire that the complete process be achievedwithin 40 to 60 seconds, depending on the condi-tions and systems used. However, prior to dis-connecting from the well and in a separateprocess that itself takes 10 to 15 seconds, allflow from the well must be controlled and nohydrocarbons must enter the sea. Both ends ofthe disconnected conduit must be sealed. Andonce the hazard clears and operation becomessafe again, connection to the well can bereestablished to resume the operation.

The tools that have been developed bySchlumberger and other companies to performthese tasks are called subsea completion andtest trees. They are not permanently fixed to theseafloor as are the production trees, but aredeployed inside the marine riser by a landingstring when needed, run through the BOP stack,

6 Oilfield Review

Schlumberger has designed a series of trees for subsea

operations, testing, completion and intervention. Combinations

of inside and outside tool diameters, pressure and temperature

ratings and control systems are designed to suit a variety of

subsea completion and well-testing applications as well as

water-depth and wellbore conditions.

> A subsea completion and test tree and subsea blowout preventer (BOP) configuration. The completionand test tree fits inside the BOP to control a live well.

Blowoutpreventer

Subseacompletion

and test tree

7. Crabtree M, Eslinger D, Fletcher P, Miller M, Johnson Aand King G: “Fighting Scale—Removal and Prevention,”Oilfield Review 11, no. 3 (Autumn 1999): 31-45.

8. For more on gas-hydrate inhibition: Brandt et al, reference 1: 11-12.

Winter 1999/2000 7

connected to the production tree tubing hangerand then retrieved (right). The tools combine twomain features: the control-system portion of thetool transmits information between the surfaceand the tool and facilitates the activation of thevalves and latches. The valves and latches per-form the connection, flow control, disconnectionand reconnection with the seafloor tree.

Schlumberger has designed a series of treesfor subsea operations, testing, completion andintervention. Combinations of inside and outsidetool diameters, pressure and temperature ratingsand control systems are designed to suit a vari-ety of subsea completion and well-testing appli-cations as well as water-depth and wellboreconditions. For well testing, the smaller diameterSenTREE3 system is used. The SenTREE3 toolhas a 3-in. inside diameter and ratings of 15,000psi [103.4 MPa], and 350°F [177°C]. For comple-tion and intervention, the SenTREE7 system isdesigned with a 73⁄8-in. internal diameter and has10,000 psi [68.9 MPa] and 325°F [163°C] ratingscapable of operating in water depths up to10,000 ft. A chemical-injection line allows addi-tives to be introduced to the well to prevent cor-rosion or hydrate formation.

Each tool’s control system is engineeredaccording to the operator’s requirements. Thetime available for disconnection depends on eachvessel’s dynamic positioning system capabilities,water depth, expected currents and waveheights, and a hazardous operations analysis. TheSenTREE tools are designed to unlatch under fulltension and at an angle greater than can be phys-ically achieved in the BOP stack, to ensure thatcontrolled unlatching is possible in all conditions.In water depths to 2000 ft [610 m], under mildconditions and from a tethered or moored vessel,the time can be up to 120 seconds. The time islonger because the vessel is anchored and doesnot rely on dynamic positioning to stay in place. Inthese cases, the control system usually has adirect hydraulic design. The signal to disconnectis sent through hydraulic lines to solenoid valvesin the tool’s control system that hydraulically acti-vate the tool valves. Due to the behavior of thefluid and the control lines, the time required forthe shutoff signal to travel to the subsea toolincreases with depth. One method for minimizingthis additional time in water depths up to 4000 ft[1219 m] is to enhance the system through use ofpressure accumulators in the subsea hydraulics.

At greater water depths, or in operations froma dynamically positioned vessel, disconnectionmust be achieved in 15 seconds or less. Ahydraulic system alone, over the distanceinvolved, functions too slowly for this, but thecombination of an electrical and hydraulic systemallows a fast electrical signal to activate thehydraulically controlled disconnection and flowshutoff. These systems are known as electrohy-draulic. For the SenTREE3 system, the surface sys-tem sends a direct electric signal on an electricalcable to the three solenoid valves of the downholecontrol system. These valves control the threefunctions of the SenTREE3 tool, which are to closeshutoff valves, vent pressure and unlatch.

The SenTREE7 multiplex control system, onthe other hand, performs 24 functions. Theseinclude opening and closing four valves, latchingand unlatching two tools, locking and unlockingthe tubing hanger, injecting chemicals and moni-toring temperature and pressure (right andbelow). The system is too complicated to operateby direct electrical signal, so a multiplexed signalis sent down a logging cable, then interpreted bya subsea electronics module in the control sys-tem, which in turn activates the tool functions. Inaddition, the electrical system telemeters feed-back on the pressure, temperature, status of thevalves, and other parameters as required, provid-ing two-way communication between tool andsurface. The Schlumberger multiplexed controlsystem is the fastest proven method available.

The shutoff system comprises a ball valve,flapper valves and a latch. A tubing-hanger run-ning tool (THRT) completes the system. A slickjoint separates the various valves and latches tomatch the spacing of the rams of any subsea BOP

8 Oilfield Review

> Inside the SenTREE7 system. Theelectronics module (above) interpretsmultiplexed signals sent from the surface to control tool functions.Hydraulic lines (left) transmit the signals to the tool’s valves and latches.

Winter 1999/2000 9

configuration so the rams can close in the case ofa blowout (below). The valves are specified to holdpressures exerted from inside or outside the sys-tem. To ensure fluid isolation, the valves operatein order: first, the ball then lower flapper valvesshut off fluid rising from the well; second, theretainer valve above the latch closes to containfluids in the pipe leading to the surface; third, thesmall amount of fluid trapped between the twovalves is bled off into the marine riser; finally thelatch disconnects the upper section, which can bepulled clear of the BOP stack. If the riser is goingto be disconnected at the same time, the BOPblind rams are then closed and the drilling riser isdisconnected. The vessel then can move off loca-tion leaving the well under control. The design ofa subsea completion and test tree centers on the

ability to perform a controlled disconnection—anevent that both operator and service companyhope will never happen, but must have the capa-bility to manage should it occur.

The design and manufacturing process forcompletion and test trees is quite different fromthat of other oilfield service tools. Other oilfieldservice tools, such as wireline or logging-while-drilling tools, are typically designed by servicecompanies to be used hundreds of times in manywells and to suit a wide variety of conditions.Subsea completion and test trees consist of stan-dard modules, but must be adapted to suit pro-ject specifications driven by BOP dimensions,shear capability and tubing-hanger systemdimensions, all according to a tightly timeddevelopment and delivery contract.

Spanner joint

Retainer valveBleedoff valve

Shear sub

Latch assembly

Valve assembly

Slick joint

Adjustablefluted hanger

Riser

Hydril

Shear rams

Blind rams

Pipe rams

Pipe rams

BOP stack

SenTREE3 tool

SenTREE series of subsea test and completion tools. The SenTREE3(left) and SenTREE7 (right) toolshave similar design, with valves and latches to shut off fluid flow and disconnect from the well in acontrolled operation. The SenTREE3tool (yellow) is displayed inside aBOP stack (green). The componentsof the SenTREE7 system are labeled in order of their activation in theevent of a disconnection.

Lubricator valve

Control system

Bleedoff valve

Retainer valve

Latch connector

Flapper valve

Ball valve

4

2

3

5

1

SenTREE7 tool

>

Multiple vendors participate in building dif-ferent components of a subsea installation, andeach component must fit and work with others onschedule. Delays in tool availability mean delaysin production. The tools themselves are physi-cally colossal (above). Even the largest wirelinetools fit inside. The substantial dimensions andweight of this equipment require special han-dling equipment and cranes for moving andmanipulation. Tool operation, handling and main-tenance are usually carried out by locations thatalso handle well-testing equipment.

Each completion and test tree must be adaptedto fit a specific subsea production tree and BOPcombination, of which it seems no two are alike.

The first production trees were mainly “dual-bore” type trees, with a production bore and sep-arate annulus bore passing vertically through thetree and with valves oriented vertically. Therewere also a number of concentric-bore treedesigns in which the annulus could not beaccessed.9 Both the dual-bore with separate bores

and the concentric-bore trees are sometimescalled vertical trees by some manufacturers.

A disadvantage of this type of tree is that it is installed on top of the tubing hanger, sothat if the tubing must be pulled for a workover,the production tree—often a 30-ton item—must be removed. In some cases, this may alsoinvolve the removal of umbilicals or evenpipeline connections.

In 1992 a different style of production tree,the horizontal tree, was introduced. In the hori-zontal tree, the production and annulus boresdivert out the sides of the tree and the valves areoriented horizontally. These are sometimescalled side-valve or spool trees. Since the tubingis landed inside a horizontal tree, the tubing canbe accessed or pulled without moving the tree,making intervention much easier. Each type ofproduction tree has a different arrangement withthe BOP, wellhead and tubing hanger, and sorequires its own completion and test tree.

The unique design and the union of electricaland hydraulic methods in the control systemmake the Schlumberger SenTREE7 subsea com-pletion and test tree highly versatile and adapt-able to the needs of the project at hand (nextpage). The subsea completion and test tree iscustom-engineered to fit inside a BOP with anyram spacing and to interface with any tubing-hanger running tool.

10 Oilfield Review

Certificates from Det Norske Veritasissued when modulespass their factoryacceptance test, andGary Rytlewski, subseachief engineer at theSchlumberger ReservoirCompletions center.

> A tool as big as the team. The SenTREE engineering team at the Schlumberger Reservoir Completions center in Rosharon, Texas, USA accentuates the large scale of the SenTREE7 tool.

9. Richborg MA and Winter KA: “Subsea Trees andWellheads: The Basics,” Offshore 58, no. 12 (December 1998): 49, 51, 53, 55, 57.

>

Winter 1999/2000 11

Tool ReliabilityThe primary consideration in selecting a subsea completion and test tree is reliability.Schlumberger ensures reliability of completionand test trees through meticulous, systematictesting. Every component of every tool undergoestests with multiple levels of scrutiny.

The first formal test is the factory acceptancetest (FAT), in which individual modules are testedin-house. The test is conducted in the presence

of a representative from Det Norske Veritas whowitnesses the test and reviews the calculationpackage that shows how that module wasdesigned to work (previous page, bottom).

However, calculations alone do not prove thata tool will function under the extreme conditionsof the subsea environment. Operators need morethan numerical computations when the safety ofpersonnel, equipment and the environment is at

stake. The cost of deploying a substandard sub-sea tool at current rig day rates—a day or moreto run the tool to depth, a few hours to discover itis malfunctioning, and another day or two to bringit back to surface—can reach the million-dollarmark, not counting any repairs. Reliability of othertypes of equipment can be proved in laboratorypressure vessels, but testing a subsea completiontree in a pressure vessel is not an easy task. For

>Engineers assembling a SenTREE7 tool for testing at the Schlumberger Reservoir Completions center.

this purpose, the Schlumberger ReservoirCompletions group designed and constructed anoversized high-pressure test facility (above).

The hyperbaric test facility at Rosharon, Texas,USA was constructed by excavating a 35-ft [11-m]deep pit and creating a 19-in. [48-cm] inner-diam-eter hole to hold an entire completion tree at con-ditions equivalent to those at 10,000-ft waterdepth. Here, any subsea pressure scenario can becreated to match conditions expected for any joband prove that the tool will function properly.

Qualification tests ensure that modules com-ply with specific industry standards of functionand performance, such as those established by

the American Petroleum Institute (API). For exam-ple, any number of API standards specify that amodule must perform at a given temperature,pressure and flow rate, with various fluids, for agiven length of time. These tests are conductedby the Southwest Research Institute in SanAntonio, Texas, according to industry benchmarksthat other subsea equipment must also meet.

Another test that requires third-party involve-ment is the system integration test (SIT) at whichall components from all vendors are assembledin a simulation of a real subsea operation. Theclient is usually present to witness the integrated

test. Typical equipment and services present atthe SIT are the subsea production tree, manifold,flexible and hard flowlines, umbilical control,SenTREE7 subsea completion test tree and con-trol system, tubing-hanger running tool, tubinghanger, slickline unit, dummy ROV, cranes and allthe expected field personnel. In some cases, theconnectors for permanent monitoring systemsand the associated test equipment are also partof the SIT. Any interface between the SenTREE7tool or tubing-hanger running tool and an intelli-gent or advanced completion would be incorpo-rated in the SIT, thus helping eliminate potential

12 Oilfield Review

5000-psiexternal pressureBelow valve zone

Above valve zone

8x control functions

SenTREE7test tree

Latch system tolock in tubing-hanger running tooland tubing hanger

> Massive in-ground high-pressure laboratory for proving subsea tool reliability, with ground-level wellhead(insert). Conditions can be created tomatch those expected for any subseainstallation down to 10,000-ft water depth.

Winter 1999/2000 13

costly offshore interface problems. This approachensures that the equipment will work togetherproperly in the field.

The following sections include field examplesthat demonstrate the roles completion and testtrees play in the different phases of well life,from exploration and completion to interventionand abandonment.

Well TestingIn the exploration stage of a well, after a potentialpay zone is discovered, a well test is conducted toevaluate the production and flow capabilities ofthe well. To test a subsea well, a drillstem test(DST) string is run through the BOP. A typical DSTstring consists of perforating guns, gauges, agauge carrier with surface readout capabilities, aretrievable packer and a test-valve tool. This isconnected by tubing up to the seabed, then to aretrievable well-control test tree set in the BOP toensure that disconnection, if required, is done in acontrolled way. Reservoir fluids flow past the DST

gauges at the reservoir level where pressure andtemperature are detected, then flow through thetubing and test tree, and finally to the surface.

In 1974, when Flopetrol-Johnston Schlumbergerintroduced the first subsea test called the E-Z Treetool, testing operations from a floating vesselwere made possible with the required level ofsafety. Since then, the technology has evolvedand other companies have developed relatedtools. Halliburton and Expro now offer similartest trees and services, and Schlumberger hasdeveloped the SenTREE3 test tree.

In one subsea testing job for Chevron, the controlled disconnect ability of the SenTREE3system was confirmed under severe weatherconditions. The North Sea well was at a waterdepth of 380 ft [116 m]. The SenTREE3 tool wasequipped with a hydraulic control system. Theheavy-oil test was conducted with an electricsubmersible pump and a drillstem test tool.Weather conditions deteriorated until the aver-age heave reached 15 ft [4.6 m]. At this time, the

operator decided to halt the test and unlatch. Theshutoff valves were activated and the tool wasunlatched and drawn up (below left). The riserwas disconnected and the vessel moved off.

By the time the weather calmed down, thewell test was cut short and the primary objectivewas then to relatch and retrieve the drillstem testtool. The reconnection was performed success-fully and the DST was recovered to surface.

Another example of subsea testing successcomes from the Barden field in the NorwegianNorth Sea operated by a consortium consistingof Norsk Hydro, BP, Shell, Statoil and SagaPetroleum. Early in 1998, the operators decidedto evaluate the new discovery with theSenTREE3 tool and were the first in the world touse the Schlumberger electrohydraulic controlmodule (below). The dynamically positionedOcean Alliance maintained position in the 857-m[2812-ft] deep rough waters. With this combina-tion of potentially rough seas and moderatedepth, the ability to disconnect quickly is even

> Emergency disconnect of SenTREE3 system during a well test for Chevron.The hydraulic control system unlatched the subsea test tree when weatherconditions became hazardous, and successfully reconnected to retrieve the test tree and drillstem test tool once the weather moderated.

> The SenTREE3 tool with electrohydrauliccontrol used for testing the Barden field inthe Norwegian North Sea.

more critical than in deeper water, because theangle of the riser relative to vertical changesmore quickly as the vessel moves off station,and the maximum feasible unlatch angle isreached sooner.

Fortunately, the weather remained temperatethroughout the full seven days of the well test. Apressure and temperature sub inside theSenTREE3 tool monitored flowing conditions toassist in the prevention of hydrates. Reservoirfluids flowed through the IRIS Intelligent RemoteImplementation System test string. The produced

liquid hydrocarbons were flared with the newEverGreen burner that generates no smoke orsolid fallout.

In the three years since its introduction, thisnew subsea testing technology has spread toother exploration provinces. Two other well testshave been conducted with the SenTREE3 toolplus electrohydraulic control system—one off-shore Brazil, the other offshore Nigeria. Almost300 other jobs have been run offshore Brazil,West Africa, Australia, Indonesia and in the Gulfof Mexico with the SenTREE3 test tree and thehydraulic or enhanced hydraulic control systems.

CompletionThe operations described so far pertain to subseaexploration and appraisal wells with temporarycompletions: after testing, the packer, test stringand tubing are pulled and the BOP is left in control of the hole for either abandonment orsidetrack operations. Installing a permanentcompletion, or string of production tubing, is per-formed in the development phase when produc-tion wells are drilled and completed or when anexisting well is recompleted. The basic processof completing a subsea well with a horizontalproduction tree can be described as a series offive steps, with a number of subtasks within thefive broad categories:

14 Oilfield Review

1 2 3 4

5. Run subsea horizontal tree. 6. Land the tree, lock connector, test seals and function valves with ROV. Establish guidewires and release tree-running tool. 7. Run BOP stack onto horizontal tree, lock connector, run BOP test tool and test, function-test tree. 8. Retrieve suspension packer, remove wearbushing fromtree, make up SenTREE7 system, rack back.

5 6 7 8

13 3/8-in.casing

Suspensionpacker

10 3/4 by 9 5/8-in.casing

> Subsea completion sequence. 1. Complete drilling and install the suspension packer. 2. Retrieve the drilling riser and BOP stack, move rig off. 3. Retrieve drilling guidebase with ROV assistance. 4. Run the production flow base and latch on 30-in. wellhead housing.

Winter 1999/2000 15

Well suspension—Suspend flow from thewell with kill fluid; run plugs to shut off flow;retrieve the riser and BOP.

Production tree installation—Install the horizontal tree; rerun the drilling BOP; recoverplugs and temporary suspension string.

Completion—Change to completion fluid;condition the well prior to running completion;run the completion with production equipmentand the subsea completion and test tool.

Installation and intervention—Close rams;land off and test hanger; set and test packer;underbalance the well; perforate; clean up flow;pull out the landing string.

Isolation and production preparation—Runand set hanger plug; open rams; unlatch tubing-hanger running tool (THRT); pull THRT out of hole

with landing string. Run internal tree cap; run andset internal tree cap plug.10 Unlatch THRT frominternal tree cap; recover landing string; recoverBOP and riser.

Two oilfield service companies, Expro andSchlumberger, offer tools and services for com-pleting large-bore, horizontal-tree subsea wells.ABB Vetco Gray, an engineering company thatalready supplies tubing hangers, is activelydeveloping capability to offer completion ser-vices also. As service providers gain experiencewith and compile success stories about subseacompletions with horizontal trees, operators willlearn about the advantages the newer trees offerin terms of ease of completion and intervention.

Late in 1999, Shell in Sarawak, Malaysia real-ized considerable savings by advancing quickly

from exploration to production using an “off-the-shelf” horizontal subsea tree—the company’sfirst horizontal tree. Using the SenTREE7 com-pletion tree, they successfully completed thesubsea well 12 days ahead of schedule without aminute of downtime. Schlumberger becameactive in the earliest planning stages of the project. This early involvement ensured that theproject would proceed as smoothly as possible.

The completion proceeded in a series of stepsbeginning with the termination of drilling andcontinuing through landing the production tree,running the completion string with the SenTREE7tool, and tying into a well-test package (previouspage, above and next page, top).

1413 1615

1211

7-in.production

liner

Perforatinggun

13. Carry out production test, acid stimulation and multirate test. 14. Unlatch THRT and retrieve landing string and SenTREE7 tool. Rig down production testpackage and flowhead. 15. Run internal tree cap. 16. ROV closes tree valves. Retrieve THRT and landing string.

(continued on page 16)

10. A tree cap is a cover that seals the vertical conduits in asubsea production tree.

9

7 5/8-in.premium-thread

chrome tubing

7-in. polish borereceptacle (PBR)

with seal units

9 5/8 by 7-in.permanentproduction

packer

10

9. Run completion string, make up tubing-hanger running tool (THRT) and SenTREE7 system on tubing hanger, run landing string with umbilical, make up surface control head to landing string. 10. Land hanger in production tree and test seals. Rig up wireline and retrieve straddle sleeve. Run seat protectors.Circulate tubing to potable water for drawdown. Set wireline plug, test string and set packer. 11. Rig up production test package. Rig up electric wireline and lubricator. 12. Run guns, correlate and perforate well.

1817 19 20

By mid-1999 Texaco had set a record for deep-water subsea completions in their Gulf of MexicoGemini field (below). The enhanced directhydraulic SenTREE7 subsea completion treeassisted in the completion process of three subseawells in 3400 ft [1037 m] of water, at the time aworldwide industry record for this type of subseacompletion system. The enhanced direct hydraulicSenTREE7 system helped run the 5-in. completionstring along with a Cameron tubing hanger on 7-in., 32-lbm/ft [14.5-kg/m] landing string. Thecompletions were performed from the DiamondOffshore Ocean Star, an anchored vessel, and theenhanced hydraulic control system provided the

requisite 120-sec response time to control thewell and disconnect the landing string if required.

After the completions, surface well testswere performed from the anchored vessel. Thefirst well was flowed back to the DiamondOffshore Ocean Star for a total of 65 hours, witha final gas rate of 80 MMscf/D [2.2 million m3/d],condensate at 1500 bbl/day [238 m3/d] and waterat 200 bbl/day [32 m3/d]. Methyl alcohol wascontinually injected at the SenTREE7 chemical-injection line to prevent formation of hydratesduring the flowback period. The SenTREE7 toolwas also used to facilitate the installation of theinternal tree cap. Schlumberger also provided

surface well test equipment and services andsand-detection equipment during well cleanup.All services, including SenTREE7 operation, wereperformed with 100% uptime.

Since then the water-depth record has beenbroken, again by the SenTREE7 tool, in anotherGulf of Mexico field. Late in 1999, a Schlumbergercompletion and test tree operated from ananchored vessel as before, but this time in waterdepths of 4650 ft [1417 m]. The record was setduring completion of a five-well developmentusing a tool system similar to the one deployed inthe Gemini field: the enhanced direct control sys-tem assured a 120-sec response time.

16 Oilfield Review

> Gemini field subsea development. Three Texaco subsea wells in the Gulf of Mexico were completedusing the SenTREE7 system from an anchored vessel.

> Subsea completion sequence (continued). 17. Retrieve BOP stack, retrieve guidewires. 18. Install debris cap, deploy telescopic legs. 19. Suspend well. 20. Tie in to pipeline for production.

Winter 1999/2000 17

Completions of this nature have been per-formed on wells in Africa, the Gulf of Mexico andthe UK, and more are being planned for the year2000. After the exceptional experience in theGemini field, Texaco has selected Schlumbergerfor completions services in 15 subsea wells in itsNorth Sea Captain field. And more multiwell con-tract arrangements have been made with majoroil companies operating in the Gulf of Mexico.

In particular, BP Amoco has signed a three-year multiwell contract with Schlumberger forsubsea completions services in its Gulf of Mexicofields. Two of these reach water depths of 7000 ft[2134 m]. These wells will be completed fromEnterprise, a dynamically positioned drillship,and so will require the multiplexed deepwatercontrol system that provides a 15-second con-trolled disconnect. The entire multiplex systemhas already completed a rigorous qualificationtest and met stringent BP Amoco requirements,including the 15-second disconnect time. BPAmoco purchased a surface well-test packagethat was installed on the Enterprise for use as awell test and early production facility.11

Schlumberger well intervention group developedthe subsea intervention lubricator (SIL). The SIL isdesigned to be deployed and operated from asuitably equipped dynamically positioned vesseland permits wireline or coiled tubing access tolive subsea wells without the requirement of aconventional BOP stack and marine riser.Wireline techniques have limited application inthe hundreds of subsea wells that are highlydeviated or horizontal. An intervention systemmust be able to convey tools and fluids in high-angle wells. Coiled tubing often offers thesecapabilities.

At the end of 1997, the world’s first suchcoiled tubing intervention was carried out fromthe CSO Seawell on the Gannet field for Shell inthe North Sea. Representatives from theSchlumberger well intervention services group,Dowell, Coflexip Stena Offshore and ShellSubsea Well Engineering and UnderwaterEngineering together assessed the risks associ-ated with the development of the system. A cus-tom-built lifting and shipping frame was installedon the CSO Seawell to keep the riser in tensionand deploy the coiled tubing. The system was

InterventionMost wells require some kind of intervention dur-ing their life span. Interventions—installing orservicing subsurface surface-control valves,changing gas-lift valves, production logging,pulling failed tubing, removing scale or paraffins,perforating new sections, squeezing cement intoperforations to shut off water flow—all canextend the productive life of a well. Some com-panies claim that more than half their productioncomes from subsea wells, and they will not tol-erate reduced production that can be amelioratedthrough intervention.12

Intervention can be and has been accom-plished with a drilling rig and marine riser, butreturning to a subsea well using this approach isan expensive proposition. This has led the indus-try to seek more cost-effective methods for subsea intervention.

Subsea well intervention services ofSchlumberger, together with Coflexip StenaOffshore (CSO), have devised a cost-effectivealternative for light well intervention—interven-tion that can be run through tubing. CoflexipStena Offshore built the specially designeddynamically positioned monohull vessels, CSO Seawell and CSO Wellservicer. The

11. For more on early production systems: Baustad T,Courtin G, Davies T, Kenison R, Turnbull J, Gray B, Jalali Y, Remondet J-C, Hjelmsmark L, Oldfield T, Romano C, Saier R and Rannestad G: “Cutting Risk,Boosting Cash Flow and Developing Marginal Fields,”Oilfield Review 8, no. 4 (Winter 1996): 18-31.

12. McGinnis E: “Coiled Tubing Performance UnderliesAdvances in Intervention Vessels,” Offshore 58, no. 2(February 1998): 46-47, 72.

tested first on a suspended wellhead and suc-cessfully performed a series of operations: rou-tine disconnect and reconnect; swivel check;coiled tubing run in hole; logging and circulating;emergency disconnect with 1100 psi [7587 KPa]in riser; and rigging down. On the live Gannetwell, a coiled tubing-conveyed production log-ging test was conducted over four days with nononproductive time (below).

more cost effectively from a dynamically posi-tioned dive-support vessel—a vessel not speciallyequipped for drilling. The two key factors in favorof the new approach with a dive-support vesselwere reduced cost of implementation of thestreamlined task and lower risk due to the short-ened program with minimal hardware recovery.

The abandonment plan maximized efficiencyby executing the operation in two parts—first allwells would be plugged, then all subsea produc-tion trees and wellheads would be recovered.This optimized equipment rental costs and madeit possible for the crew to improve the process byrepeating and learning one type of operation.

The job was performed by the Coflexip StenaOffshore Ltd. CSO Seawell using the subseaintervention lubricator. During the pluggingphase of the plan, the SIL maintained control ofand provided access to each well to carry kill-weight fluid to the open perforations, perforatethe tubing, circulate cement, pressure test theplugs, circulate test dye, perforate casing and cutthe tubing with explosives. In the second phase,the subsea production tree and tubing hangerwere recovered, casing strings were cut explo-sively at least 12 ft [4 m] below the seabed andthe wellhead and casing stumps retrieved. Theoptimized operation took 47 days instead of the81 planned.

To date, 142 subsea production and sus-pended wells encompassing 8 complete produc-tion-field abandonments have been carried out inthe UK continental shelf using the CSO Seawelland the SIL.

For deepwater subsea wells, abandonment ismore involved. Late in 1999, EEX Corporationbegan decommissioning its Cooper field in theGarden Banks area of the Gulf of Mexico—thefirst such project performed at a water depthgreater than 2100 ft [640 m] from a dynamicallypositioned vessel.15 Schlumberger and severalother contractors worked with Cal Dive Inc.through the complex operation that includedremoval of a one-of-a-kind freestanding produc-tion riser, 12-point mooring system, floating pro-duction unit and all the subsea equipment.Schlumberger provided subsea project manage-ment expertise along with coiled tubing, pump-ing, slickline, testing and wireline services.

The first step in decommissioning the fieldwas to kill the seven subsea wells. Once this wasaccomplished, the riser, flowlines, productiontrees and export pipelines were all cleaned and

18 Oilfield Review

CSO Seawell

Rigid riser

Subseainterventionlubricator

Subsea tree

Coiled tubingproduction logging

> Light intervention services on subsea wells from a dynamically positioned monohull vessel using the subsea intervention lubricator. Cost-effective subsea intervention, in the form of coiled tubing-conveyed production logging, was performed in the Gannet field, North Sea.

Since the SIL was developed in 1985, morethan 1166 operational days have been registeredand more than 275 subsea wells have beenentered using the lubricator from the CSOSeawell.13 Key factors in the success of theapproach have been efficiency and cost-effec-tiveness of operations. Compared with opera-tions from a mobile drilling unit, cost savings canrange from 40 to 60%.

AbandonmentAs more provinces mature and prolific fieldsdecline, operators must contend with subseawell abandonment—as challenging a prospectas any other subsea well operation. Well controlmust be maintained at all times, and abandon-ment guidelines must be heeded. These varywith government and regulatory agencies, butgenerally include points regarding the depthbelow the seafloor to which all equipment mustbe cleared, the isolation of producing zones fromeach other, and the isolation of producing zonesand overpressured or potential producing zonesfrom the seabed. Operators want to minimizeexpense at this stage in the life of the well, socost remains a large concern.

One of the first major subsea well-abandon-ment projects carried out in the North Sea was forthe Argyll field in the UK sector.14 In 1975, the field,in 260-ft [79-m] water depth, had been the first tobegin production in the North Sea. By 1992, 35wells had been drilled, of which 18 were com-pleted subsea, and 7 of those had been shut in.Production could not be sustained much longer. Atthat time, conventional abandonment involvedretrieving the completion and setting cementplugs through drillpipe from an anchored ordynamically positioned semisubmersible drillingrig. This process would take 8 to 10 days per well.

An innovative alternative proposal called forsqueezing cement into the productive perforationsthrough the production tubing and cementing thewhole completion into place. This could be accom-plished in about four days per well with the samedrilling rigs as the conventional abandonment, or

Winter 1999/2000 19

flushed. The mooring lines, chains and anchorswere moved off-site, and the seven wells wereplugged and abandoned using a combination ofwireline and specially designed coiled tubingunit. Because the entire abandonment operationwas conducted from the Uncle John, a dynami-cally positioned semisubmersible, the systemalso used an emergency disconnect package.After the wells were plugged, the subsea treesand remote templates were retrieved. The flow-lines and export lines were then filled withtreated salt water and sealed. These lines, alongwith the main template, were left in place on theseabed in such a way that, if required, they couldbe used to support future regional development.

What Next for Subsea?Many companies already are experienced withsubsea solutions and others are just beginning tobecome familiar with the advantages and limita-tions. All agree that although the industry hasachieved measurable advances since the firstsubsea well almost 40 years ago, more work hasto be done before subsea technology can beapplied everywhere it is needed.

Nearly all of the current limitations arerelated to the extreme depths and operating con-ditions encountered by subsea wells. One broadcategory of work to be done concerns metallurgy.Embrittlement of metals at subsea temperaturesand pressures causes failures in equipment.Going deeper may require completely new typesof materials.

Another area of investigation addresses risers, moorings and umbilicals. Groups arelooking into assessing induced vibrations ondrilling risers and the possibility of developingpolyester moorings.

Elsewhere, other initiatives have been under-taken. PROCAP2000 in Brazil supports theadvancement of technologies that enable produc-tion from waters to 2000 m [6562 ft] depth. Sinceits inception in 1986, many of the group’s targetshave been reached, but several subsea projectsconcentrating on subsea multiphase flow meter-ing, separation and pumping are continuing.

The Norwegian Deepwater Programme wasformed in 1995 by the deepwater license partici-pants on the Norwegian shelf, including Esso, BPAmoco, Norsk Hydro, Shell, Saga and Statoil. Thegoal was to find cost-effective solutions to deep-water challenges and included acquiring weatherand current data, constructing a regional modelof the seabed and shallow sediments, determin-ing design and operational requirements, andaddressing problems related to flowlines, umbili-cals and multiphase flow.17

These joint efforts have been established notwith just subsea technology in mind, but touncover solutions for exploration and productionin deep water in general. However, many opera-tors are choosing subsea as their long-termdeepwater development concept. By some esti-mates, 20% of the global capital investments inoffshore field developments are in subsea facili-ties and completions.18 This percentage is likelyto rise, especially as subsea equipment contin-ues to prove reliable, flow-assurance problemsare solved and operators gain confidence in sub-sea practice. —LS

One of the ways the industry is looking forinnovation is through consortia, initiatives andjoint efforts. One of these, DeepStar, is a group ofGulf of Mexico participants from 22 oil companiesand 40 vendors and contractors.16 The oil compa-nies have specified areas in which new deepwa-ter solutions must be found. First on their list isflow assurance. Paraffins and hydrates are themain causes of flow blockage in long tiebacks. Ifways could be found to combat their deposition,longer tiebacks could be possible and economicthresholds could be lowered, allowing develop-ment of reserves that are currently marginal.

Several companies are working on solutionsto these problems. Some are proposing and try-ing methods that attempt to unclog flowlineswith coiled tubing-conveyed tools. Others aretesting the feasibility of heating pipe to controlparaffin and hydrate formation. In addition, theDeepStar organization has begun construction ofa field-scale test facility in Wyoming, USA. The5-mile [8-km] flow loop will be used to validatehydrate-prediction software and multiphase flowsimulators, test new hydrate inhibitors, observethe initiation of hydrate plugs, evaluate sensorsand understand paraffin deposition. Much morework is needed to ensure that subsea wells andlong tiebacks can sustain flow.

As more provinces mature and prolific fields decline, operators

must contend with subsea well abandonment—as challenging

a prospect as any other subsea well operation. Well control

must be maintained at all times, and abandonment guidelines

must be heeded.

13. Stewart H and Medhurst G: “A Decade of Subsea WellIntervention,” presented at World Oil 6th InternationalCoiled Tubing & Well Intervention Conference andExhibition, Houston, Texas, USA, February 9-11, 1998.

14. Prise GJ, Stockwell TP, Leith BF, Pollack RA and Collie IA: “An Innovative Approach to Argyll FieldAbandonment,” paper SPE 26691, presented at the SPE Offshore European Conference, Aberdeen,Scotland, September 7-10, 1993.

15. Furlow W: “Field Abandonment,” Offshore 59, no. 10(October 1999): 114.

16. Silverman S and Bru JG: “Taking the Initiative,”Deepwater Technology, Supplement to PetroleumEngineer International 72, no. 5 (May 1999): 54-56.

17. Silverman and Bru, reference 16.18. Thomas, reference 6.