Oil Field Review Winter 1999 English

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2 Oilfield Review

Subsea Solutions

Alan ChristieAshley Kishino

Rosharon, Texas, USA

John Cromb

Texaco Worldwide Exploration

and Production

Houston, Texas

Rodney Hensley

BP Amoco Corporation

Houston, Texas

Ewan Kent

Brian McBeathHamish Stewart

Alain Vidal

Aberdeen, Scotland

Leo Koot

Shell

Sarawak, Malaysia

For help in preparation of this art icle, thanks to RobertBrown, John Kerr and Keith Sargeant, SchlumbergerReservoir Evaluation, Aberdeen, Scotland; and Michael

Frug, 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 Review10, no. 1 (Spring 1998):2-21.


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Winter 1999/2000 3

The mysteries and challenges of the world under

the sea have long enticed adventurers and

explorers. For thousands of years, people have

speculated on the existence of underwater civi-

lizations and dreamed of discovering lost cities or

developing 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; research

devices monitor properties of the earth and sea;

and military surveillance equipment tracks suspi-

cious activityall as extensions of processes

that also take place on land.Similarly, the oil and gas industry has

extended its early exploration and production

operations with land-based rigs, wellheads and

pipelines to tap the richness of the volume of

earth covered by ocean. This evolution from land

to sea has occurred over the past century, start-

ing in 1897 with the first derrick placed atop a

wharf on the California (USA) coast (right).1

Seagoing drilling equipment followed, with off-

shore platforms, semisubmersible and jackup

drilling 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 conquer

increasingly hostile and challenging environ-

ments, offshore drilling moved forward in two

major directions: First, and predictably, wells

were drilled at greater water depths every year,

until the current water-depth record was

achieved6077 ft [1852 m] for a producing well

in the Roncador field, offshore Brazil.2 Drilling for

exploratory purposes, without actually producing,

has been accomplished at the record depth of

9050 ft [2777 m] for Petrobras offshore Brazil.Other

Gulf 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 International72, 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

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

1911First 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]


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Winter 1999/2000 5

More and more of the operations originally

performed at surface are moving to the seafloor.

Todays subsea technology covers a wide range

of equipment and activities: guidewires for low-

ering equipment to the seafloor; Christmas, or

production, trees; blowout preventers (BOPs);

intervention and test trees; manifolds; templates;

ROVs; flowlines; risers; control systems; electri-

cal power distribution systems; fluid pumping

and metering; and water separation and reinjec-

tion. One futuristic vision even depicts a seafloor

drilling rig.4

The first subsea production tree was installed

in 1961 in a Shell well in the Gulf of Mexico.5

Within 36 years, 1000 wells had been completed

subsea. Industry champions predict that complet-

ing the next 1000 will take only another five

years, and that expansion will continue at around

10% per year for the next 20 years.

In some areas, such as the Gulf of Mexico and

offshore Brazil, expansion will require pushing

the frontiers of depth-limited technology. Only

two wells in the world have been completed sub-sea at greater than a 5000-ft [1524-m] water

depth. Increases in the number of subsea com-

pletions are projected for all depths, but the most

striking will be for the ultradeep (above).6

In other areas, the North Sea in particular,

growth is evident in the increasing number of

subsea completions per project. Norsk Hydro is

planning to develop the Troll field with more than

100 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 completing

a subsea well and explains the workings of the

equipment that controls access to the well

through every stage of its existence, from explo-

ration, appraisal and completion to intervention

and abandonment.

Why Subsea?

Describing the full process behind choosing one

deepwater development strategy over another is

also beyond the scope of this article, but a briefoverview will help set the background. As in the

planning of any asset development, the decision-

making process attempts to maximize asset

value and minimize costs without compromising

safety and reliability. The cost analysis focuses

on capital expenditures and operating expenses,

and also includes risk, or the potential costs of

unforeseen events.

The conditions driving these costs are numer-

ous and interrelated, and include all the reser-

voir-related factors usually considered in

land-based development decisions, plus those

arising from the complexities of the offshoreenvironment. An abbreviated list includes exist-

ing infrastructure, water depth, weather and cur-

rents, seabed conditions, cost of construction

and decommissioning of permanent structures,

time to first production, equipment reliability,

well accessibility for future monitoring or inter-

vention, and flow assurancethe ability to keep

fluids flowing in the lines.

Certain of these conditions pose awesome

challenges for any offshore development, and

present strong arguments for subsea completion

instead of or combined with other options such

as 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 to

existing production platforms can be completedsubsea and tied back to the platform. The tieback

distance is constrained by flow continuity

seafloor stability and currents. With some fixed

platform capital expenditures measured in

billions of dollars, maximizing reservoir access

through additional subsea wells can increase

production while keeping capital and operating

costs down.

Wells whose produced fluids will be handled

by an FPSO vessel are also natural candidates

for subsea completions, and not only because o

reduced time to production. Often these are

wells in locations where water depth andweather make more permanent structures

impractical or uneconomical. Other options in

these environments are either the dry-tree unit

sometimes called a spar, which is a buoyant ver

tical cylinder, or the tension-leg platforma

floating structure held in place by vertical, ten

sioned tendons connected to the seafloor by

pile-secured templates. Both the dry-tree uni

and the tension-leg platform support platform

facilities and are anchored to the seafloor. The

latter techniques have been applied withou

subsea completions at depths reaching abou

4500 ft [1372 m], but deeper than that the solution 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

Operational

Planned

Numbe

rofsubseacompletions

> 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 EngineerInternational72, no. 5 (May 1999): 32-33, 35-37, 39.

5. Greenberg J: Global Subsea Well ProductionWill 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 International72,no. 5 (May 1999): 46, 47, 49, 50, 53.


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At the water depths in question, running

hydrocarbons through flowlines, valves and

pipelines 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 is

a problem for some reservoir compositions, usu-

ally requiring intervention at some stage of well

life. Scale deposits can also impede flow, and

need to be prevented or removed.7 The formation

of solid gas hydrates can cause blockages in

tubulars and flowlines, especially when a

water-gas mixture cools while flowing through

a long tieback. Prevention techniques include

heating the pipes, separating the gas and water

before flowing, and injecting hydrate-formation

inhibitors.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 key

consideration. Traditionally, operators have

selected platform-style solutions when the

development requires postcompletion well

access. Platforms house Christmas trees and

well-control equipment on the surface, giving

easier access to introduce tools and modify well

operations. To perform these functions on subsea

wells requires a vessel or rig, and sometimes a

marine risera large tube that connects the

subsea well to the vessel and contains thedrillpipe, drilling fluid and rising borehole

fluidsand planning for their availability when

the time comes.

All of this adds up to significant cost. In many

cases, the subsea production tree must be

removed. Reconnecting to many subsea wells to

perform workovers and recompletions can also

require a specially designed intervention system

to control the well and allow other tools to pass

through it down to the level of the reservoir. The

development of the completion test tree is now

enhancing the accessibility of subsea wells,

allowing reliable well control for any imaginableintervention. A full discussion follows in later

sections of this article.

Equipment reliability is a major concern for any

subsea installation. Once equipment is attached to

the seafloor, it is expected to remain there for the

life 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 gaining

confidence in subsea practice as contractors pro-

vide innovative and tested solutions.

EquipmentMuch of the specialized equipment for subsea

installations is designed, manufactured, posi-

tioned and connected by engineering, construc-

tion and manufacturing companies. ABB Vetco

Gray, FMC, Cameron, Kvaerner, Oceaneering,

Brown & Root/Rockwater, McDermott, Framo

and Coflexip Stena are among the companies

that supply most of the BOPs, wellheads, tem-

plates, production trees, production control sys-

tems, tubing hangers, flowlines, umbilicals,

ROVs, multiphase meters and pumps, separators

and 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 and

other groups provide special tools and services

for the subsea environment. Baker Hughes,

Halliburton, Expro, Schlumberger and others

have developed solutions to crucial wellbore-

related problems.

One of the key concerns in constructing and

operating a subsea well is maintaining well con-

trol at all times. Drilling, completion and subse-

quent servicing of subsea wells are typically

performed from one of two types of vessel: a

floating system that is tethered or anchored to

the seafloor; or one that maintains location over

the well with a dynamic positioning system. In

both cases, it is critical that the vessel remain in

the proper position, or on station. The position

can be described as the area inside two concen-

tric circles centered over the well location on the

seafloor. The inner circle represents the limit of

the preferred zone, and the outer circle repre-

sents the maximum acceptable limit before dam-

age occurs. The vessel activates thrusters to

propel the vessel back to the desired location if

currents or other conditions such as weather

have caused it to move off station, all while

continuing the drilling, testing, completion or

well intervention.

However, under extreme conditions, the

dynamic positioning system may be unable toremain on station or a situation may arise that

could endanger the vessel. System problems

could include the failure of the thruster system or

loss of some anchoring lines, causing the vessel

to drift off station. Other situations could include

severe weather or collisions with icebergs or

other vessels. Under such conditions, the dynam-

ically positioned vessel would drive off station.

All these cases would require disconnecting

the landing string and riser from the well. Once

the decision to disconnect from the well is made,

industry best practices for operation in deep

water with dynamically positioned vesselsrequire that the complete process be achieved

within 40 to 60 seconds, depending on the condi-

tions and systems used. However, prior to dis-

connecting from the well and in a separate

process that itself takes 10 to 15 seconds, all

flow from the well must be controlled and no

hydrocarbons must enter the sea. Both ends of

the disconnected conduit must be sealed. And

once the hazard clears and operation becomes

safe again, connection to the well can be

reestablished to resume the operation.

The tools that have been developed by

Schlumberger and other companies to performthese tasks are called subsea completion and

test trees. They are not permanently fixed to the

seafloor as are the production trees, but are

deployed inside the marine riser by a landing

string 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.


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At greater water depths, or in operations from

a dynamically positioned vessel, disconnection

must be achieved in 15 seconds or less. A

hydraulic system alone, over the distance

involved, functions too slowly for this, but the

combination of an electrical and hydraulic system

allows a fast electrical signal to activate the

hydraulically controlled disconnection and flow

shutoff. These systems are known as electrohy-

draulic. For the SenTREE3 system, the surface sys-

tem sends a direct electric signal on an electrical

cable to the three solenoid valves of the downhole

control system. These valves control the three

functions of the SenTREE3 tool, which are to close

shutoff valves, vent pressure and unlatch.

The SenTREE7 multiplex control system, on

the other hand, performs 24 functions. These

include opening and closing four valves, latching

and unlatching two tools, locking and unlocking

the tubing hanger, injecting chemicals and moni-

toring temperature and pressure (right and

below). The system is too complicated to operate

by direct electrical signal, so a multiplexed signalis sent down a logging cable, then interpreted by

a subsea electronics module in the control sys-

tem, which in turn activates the tool functions. In

addition, the electrical system telemeters feed-

back on the pressure, temperature, status of the

valves, and other parameters as required, provid-

ing two-way communication between tool and

surface. The Schlumberger multiplexed control

system 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 slick

joint 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 thesurface to control tool functions.Hydraulic lines (left) transmit thesignals to the tools valves and latches.


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Winter 1999/2000 9

configuration so the rams can close in the case of

a blowout (below). The valves are specified to hold

pressures exerted from inside or outside the sys-

tem. To ensure fluid isolation, the valves operate

in order: first, the ball then lower flapper valves

shut off fluid rising from the well; second, the

retainer valve above the latch closes to contain

fluids in the pipe leading to the surface; third, the

small amount of fluid trapped between the two

valves is bled off into the marine riser; finally the

latch disconnects the upper section, which can be

pulled clear of the BOP stack. If the riser is going

to be disconnected at the same time, the BOP

blind rams are then closed and the drilling riser is

disconnected. The vessel then can move off loca-

tion leaving the well under control. The design of

a subsea completion and test tree centers on the

ability to perform a controlled disconnectionan

event that both operator and service company

hope will never happen, but must have the capa-

bility to manage should it occur.

The design and manufacturing process for

completion and test trees is quite different from

that of other oilfield service tools. Other oilfield

service tools, such as wireline or logging-while-

drilling tools, are typically designed by service

companies to be used hundreds of times in many

wells 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 system

dimensions, all according to a tightly timed

development 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 testand completion tools. The SenTREE3

(left

) and SenTREE7 (right

) toolshave similar design, with valvesand latches to shut off fluid flowand disconnect from the well in acontrolled operation. The SenTREE3

tool (yellow) is displayed inside aBOP stack (green). The componentsof the SenTREE7 system are labeledin 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

>


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Multiple vendors participate in building dif-

ferent components of a subsea installation, and

each component must fit and work with others on

schedule. Delays in tool availability mean delays

in production. The tools themselves are physi-

cally colossal (above). Even the largest wireline

tools fit inside. The substantial dimensions and

weight of this equipment require special han-

dling equipment and cranes for moving and

manipulation. Tool operation, handling and main-

tenance are usually carried out by locations that

also handle well-testing equipment.

Each completion and test tree must be adaptedto fit a specific subsea production tree and BOP

combination, 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 the

tree and with valves oriented vertically. There

were also a number of concentric-bore tree

designs in which the annulus could not be

accessed.9 Both the dual-bore with separate bores

and the concentric-bore trees are sometimes

called vertical trees by some manufacturers.

A disadvantage of this type of tree is that

it is installed on top of the tubing hanger, so

that if the tubing must be pulled for a workover,

the production treeoften a 30-ton item

must be removed. In some cases, this may also

involve the removal of umbilicals or even

pipeline connections.

In 1992 a different style of production tree,

the horizontal tree, was introduced. In the hori-

zontal tree, the production and annulus bores

divert out the sides of the tree and the valves are

oriented horizontally. These are sometimes

called side-valve or spool trees. Since the tubing

is landed inside a horizontal tree, the tubing can

be accessed or pulled without moving the tree,

making intervention much easier. Each type of

production tree has a different arrangement with

the BOP, wellhead and tubing hanger, and so

requires its own completion and test tree.

The unique design and the union of electrical

and 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 (next

page). The subsea completion and test tree is

custom-engineered to fit inside a BOP with any

ram spacing and to interface with any tubing-

hanger running tool.

10 Oilfield Review

Certificates fromDet Norske Veritasissued when modulespass their factoryacceptance test, and

Gary Rytlewski, subseachief engineer at theSchlumberger ReservoirCompletions center.

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

9. Richborg MA and Winter KA: Subsea Trees andWellheads: The Basics, Offshore58, no. 12(December 1998): 49, 51, 53, 55, 57.

>


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this purpose, the Schlumberger Reservoir

Completions group designed and constructed an

oversized 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 water

depth. Here, any subsea pressure scenario can be

created to match conditions expected for any job

and prove that the tool will function properly.

Qualification tests ensure that modules com-

ply with specific industry standards of function

and performance, such as those established by

the American Petroleum Institute (API). For exam-

ple, any number of API standards specify that a

module must perform at a given temperature,

pressure and flow rate, with various fluids, for a

given length of time. These tests are conductedby the Southwest Research Institute in San

Antonio, Texas, according to industry benchmarks

that other subsea equipment must also meet.

Another test that requires third-party involve-

ment is the system integration test (SIT) at which

all components from all vendors are assembled

in a simulation of a real subsea operation. The

client is usually present to witness the integrated

test. Typical equipment and services present at

the 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 all

the expected field personnel. In some cases, the

connectors for permanent monitoring systems

and the associated test equipment are also part

of the SIT. Any interface between the SenTREE7

tool 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-pressurelaboratory for proving subsea toolreliability, with ground-level wellhead(insert). Conditions can be created tomatch those expected for any subseainstallation down to 10,000-ft water depth.


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Winter 1999/2000 13

costly offshore interface problems. This approach

ensures that the equipment will work together

properly in the field.

The following sections include field examples

that demonstrate the roles completion and test

trees play in the different phases of well life,

from exploration and completion to intervention

and abandonment.

Well Testing

In the exploration stage of a well, after a potential

pay zone is discovered, a well test is conducted to

evaluate the production and flow capabilities of

the well. To test a subsea well, a drillstem test

(DST) string is run through the BOP. A typical DST

string consists of perforating guns, gauges, a

gauge carrier with surface readout capabilities, a

retrievable packer and a test-valve tool. This is

connected by tubing up to the seabed, then to a

retrievable well-control test tree set in the BOP to

ensure that disconnection, if required, is done in a

controlled way. Reservoir fluids flow past the DST

gauges at the reservoir level where pressure and

temperature are detected, then flow through the

tubing and test tree, and finally to the surface.

In 1974, when Flopetrol-Johnston Schlumberger

introduced the first subsea test called the E-Z Tree

tool, testing operations from a floating vessel

were made possible with the required level of

safety. Since then, the technology has evolved

and other companies have developed related

tools. Halliburton and Expro now offer similar

test trees and services, and Schlumberger has

developed the SenTREE3 test tree.

In one subsea testing job for Chevron, the

controlled disconnect ability of the SenTREE3

system was confirmed under severe weather

conditions. The North Sea well was at a water

depth of 380 ft [116 m]. The SenTREE3 tool was

equipped with a hydraulic control system. The

heavy-oil test was conducted with an electric

submersible 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. The

shutoff valves were activated and the tool was

unlatched and drawn up (below left). The rise

was disconnected and the vessel moved off.

By the time the weather calmed down, the

well test was cut short and the primary objective

was then to relatch and retrieve the drillstem tes

tool. The reconnection was performed success

fully and the DST was recovered to surface.

Another example of subsea testing success

comes from the Barden field in the Norwegian

North Sea operated by a consortium consisting

of Norsk Hydro, BP, Shell, Statoil and Saga

Petroleum. Early in 1998, the operators decided

to evaluate the new discovery with the

SenTREE3 tool and were the first in the world to

use the Schlumberger electrohydraulic contro

module (below). The dynamically positioned

Ocean Alliancemaintained position in the 857-m

[2812-ft] deep rough waters. With this combina

tion of potentially rough seas and moderate

depth, 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 in

the Norwegian North Sea.


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more critical than in deeper water, because the

angle of the riser relative to vertical changes

more quickly as the vessel moves off station,

and the maximum feasible unlatch angle is

reached sooner.

Fortunately, the weather remained temperate

throughout the full seven days of the well test. A

pressure and temperature sub inside the

SenTREE3 tool monitored flowing conditions toassist in the prevention of hydrates. Reservoir

fluids flowed through the IRIS Intelligent Remote

Implementation System test string. The produced

liquid hydrocarbons were flared with the new

EverGreen burner that generates no smoke or

solid fallout.

In the three years since its introduction, this

new subsea testing technology has spread to

other exploration provinces. Two other well tests

have been conducted with the SenTREE3 tool

plus electrohydraulic control systemone off-

shore Brazil, the other offshore Nigeria. Almost300 other jobs have been run offshore Brazil,

West Africa, Australia, Indonesia and in the Gulf

of Mexico with the SenTREE3 test tree and the

hydraulic or enhanced hydraulic control systems.

Completion

The operations described so far pertain to subsea

exploration and appraisal wells with temporary

completions: after testing, the packer, test string

and tubing are pulled and the BOP is left in

control of the hole for either abandonment or

sidetrack operations. Installing a permanent

completion, or string of production tubing, is per-

formed in the development phase when produc-tion wells are drilled and completed or when an

existing well is recompleted. The basic process

of completing a subsea well with a horizontal

production tree can be described as a series of

five steps, with a number of subtasks within the

five 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

103/4by 95/8-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.


14/54

Winter 1999/2000 15

Well suspensionSuspend flow from the

well with kill fluid; run plugs to shut off flow;

retrieve the riser and BOP.

Production tree installationInstall the

horizontal tree; rerun the drilling BOP; recover

plugs and temporary suspension string.

CompletionChange to completion fluid;

condition the well prior to running completion;

run the completion with production equipmentand the subsea completion and test tool.

Installation and interventionClose 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 preparationRun

and set hanger plug; open rams; unlatch tubing-

hanger running tool (THRT); pull THRT out of hole

with landing string. Run internal tree cap; run and

set internal tree cap plug.10 Unlatch THRT from

internal tree cap; recover landing string; recover

BOP and riser.

Two oilfield service companies, Expro and

Schlumberger, offer tools and services for com-

pleting large-bore, horizontal-tree subsea wells.

ABB Vetco Gray, an engineering company that

already supplies tubing hangers, is activelydeveloping capability to offer completion ser-

vices also. As service providers gain experience

with and compile success stories about subsea

completions with horizontal trees, operators will

learn about the advantages the newer trees offer

in 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 treethe companys

first horizontal tree. Using the SenTREE7 com

pletion tree, they successfully completed the

subsea well 12 days ahead of schedule without a

minute of downtime. Schlumberger became

active in the earliest planning stages of the

project. This early involvement ensured that the

project would proceed as smoothly as possible.The completion proceeded in a series of steps

beginning with the termination of drilling and

continuing through landing the production tree

running the completion string with the SenTREE7

tool, and tying into a well-test package (previou

page, 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

75/8-in.premium-thread

chrome tubing

7-in. polish borereceptacle (PBR)

with seal units95/8by 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 upsurface 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 wirelineand lubricator. 12. Run guns, correlate and perforate well.


15/54

1817 19 20

By mid-1999 Texaco had set a record for deep-

water subsea completions in their Gulf of Mexico

Gemini field (below). The enhanced direct

hydraulic SenTREE7 subsea completion treeassisted in the completion process of three subsea

wells in 3400 ft [1037 m] of water, at the time a

worldwide industry record for this type of subsea

completion system. The enhanced direct hydraulic

SenTREE7 system helped run the 5-in. completion

string along with a Cameron tubing hanger on

7-in., 32-lbm/ft [14.5-kg/m] landing string. The

completions were performed from the Diamond

Offshore Ocean Star, an anchored vessel, and the

enhanced hydraulic control system provided the

requisite 120-sec response time to control the

well and disconnect the landing string if required.

After the completions, surface well tests

were performed from the anchored vessel. Thefirst well was flowed back to the Diamond

Offshore Ocean Starfor a total of 65 hours, with

a final gas rate of 80 MMscf/D [2.2 million m3/d],

condensate at 1500 bbl/day [238 m3/d] and water

at 200 bbl/day [32 m3/d]. Methyl alcohol was

continually injected at the SenTREE7 chemical-

injection line to prevent formation of hydrates

during the flowback period. The SenTREE7 tool

was also used to facilitate the installation of the

internal tree cap. Schlumberger also provided

surface well test equipment and services and

sand-detection equipment during well cleanup.

All services, including SenTREE7 operation, were

performed with 100% uptime.Since then the water-depth record has been

broken, again by the SenTREE7 tool, in another

Gulf of Mexico field. Late in 1999, a Schlumberger

completion and test tree operated from an

anchored vessel as before, but this time in water

depths of 4650 ft [1417 m]. The record was set

during completion of a five-well development

using a tool system similar to the one deployed in

the 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.


16/54

Winter 1999/2000 17

Completions of this nature have been per-

formed on wells in Africa, the Gulf of Mexico and

the UK, and more are being planned for the year

2000. After the exceptional experience in theGemini field, Texaco has selected Schlumberger

for completions services in 15 subsea wells in its

North Sea Captain field. And more multiwell con-

tract arrangements have been made with major

oil companies operating in the Gulf of Mexico.

In particular, BP Amoco has signed a three-

year multiwell contract with Schlumberger for

subsea completions services in its Gulf of Mexico

fields. Two of these reach water depths of 7000 ft

[2134 m]. These wells will be completed from

Enterprise, a dynamically positioned drillship,

and so will require the multiplexed deepwater

control system that provides a 15-second con-trolled disconnect. The entire multiplex system

has already completed a rigorous qualification

test and met stringent BP Amoco requirements,

including the 15-second disconnect time. BP

Amoco purchased a surface well-test package

that was installed on the Enterprisefor use as a

well test and early production facility.11

Schlumberger well intervention group developed

the subsea intervention lubricator (SIL). The SIL is

designed to be deployed and operated from a

suitably equipped dynamically positioned vesseand permits wireline or coiled tubing access to

live subsea wells without the requirement of a

conventional BOP stack and marine riser

Wireline techniques have limited application in

the hundreds of subsea wells that are highly

deviated or horizontal. An intervention system

must be able to convey tools and fluids in high

angle wells. Coiled tubing often offers these

capabilities.

At the end of 1997, the worlds first such

coiled tubing intervention was carried out from

the CSO Seawellon the Gannet field for Shell in

the North Sea. Representatives from theSchlumberger well intervention services group

Dowell, Coflexip Stena Offshore and Shel

Subsea Well Engineering and Underwate

Engineering together assessed the risks associ

ated with the development of the system. A cus

tom-built lifting and shipping frame was installed

on the CSO Seawell to keep the riser in tension

and deploy the coiled tubing. The system was

Intervention

Most wells require some kind of intervention dur-

ing their life span. Interventionsinstalling or

servicing subsurface surface-control valves,changing gas-lift valves, production logging,

pulling failed tubing, removing scale or paraffins,

perforating new sections, squeezing cement into

perforations to shut off water flowall can

extend the productive life of a well. Some com-

panies claim that more than half their production

comes from subsea wells, and they will not tol-

erate reduced production that can be ameliorated

through intervention.12

Intervention can be and has been accom-

plished with a drilling rig and marine riser, but

returning to a subsea well using this approach is

an expensive proposition. This has led the indus-try to seek more cost-effective methods for

subsea intervention.

Subsea well intervention services of

Schlumberger, together with Coflexip Stena

Offshore (CSO), have devised a cost-effective

alternative for light well interventioninterven-

tion that can be run through tubing. Coflexip

Stena Offshore built the specially designed

dynamically 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.


17/54

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 Gannet

well, a coiled tubing-conveyed production log-

ging test was conducted over four days with no

nonproductive time (below).

more cost effectively from a dynamically posi-

tioned dive-support vessela vessel not specially

equipped for drilling. The two key factors in favor

of the new approach with a dive-support vessel

were reduced cost of implementation of the

streamlined task and lower risk due to the short-

ened program with minimal hardware recovery.

The abandonment plan maximized efficiency

by executing the operation in two partsfirst all

wells would be plugged, then all subsea produc-

tion trees and wellheads would be recovered.

This optimized equipment rental costs and made

it possible for the crew to improve the process by

repeating and learning one type of operation.

The job was performed by the Coflexip Stena

Offshore Ltd. CSO Seawell using the subsea

intervention lubricator. During the plugging

phase of the plan, the SIL maintained control of

and provided access to each well to carry kill-

weight fluid to the open perforations, perforate

the tubing, circulate cement, pressure test the

plugs, circulate test dye, perforate casing and cut

the tubing with explosives. In the second phase,the subsea production tree and tubing hanger

were recovered, casing strings were cut explo-

sively at least 12 ft [4 m] below the seabed and

the wellhead and casing stumps retrieved. The

optimized operation took 47 days instead of the

81 planned.

To date, 142 subsea production and sus-

pended wells encompassing 8 complete produc-

tion-field abandonments have been carried out in

the UK continental shelf using the CSO Seawell

and the SIL.

For deepwater subsea wells, abandonment is

more involved. Late in 1999, EEX Corporationbegan decommissioning its Cooper field in the

Garden Banks area of the Gulf of Mexicothe

first such project performed at a water depth

greater than 2100 ft [640 m] from a dynamically

positioned vessel.15 Schlumberger and several

other contractors worked with Cal Dive Inc.

through the complex operation that included

removal 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 field

was to kill the seven subsea wells. Once this was

accomplished, the riser, flowlines, production

trees and export pipelines were all cleaned and

18 Oilfield Review

CSO Seawell

Rigid riser

Subseainterventionlubricator

Subsea tree

Coiled tubing

production logging

> Light intervention services on subsea wells from a dynamically positioned monohull vessel usingthe 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, more

than 1166 operational days have been registered

and more than 275 subsea wells have been

entered using the lubricator from the CSO

Seawell.13 Key factors in the success of the

approach have been efficiency and cost-effec-

tiveness of operations. Compared with opera-

tions from a mobile drilling unit, cost savings can

range from 40 to 60%.

Abandonment

As more provinces mature and prolific fields

decline, operators must contend with subsea

well abandonmentas challenging a prospect

as any other subsea well operation. Well control

must be maintained at all times, and abandon-

ment guidelines must be heeded. These vary

with government and regulatory agencies, but

generally include points regarding the depth

below the seafloor to which all equipment must

be cleared, the isolation of producing zones from

each other, and the isolation of producing zones

and overpressured or potential producing zonesfrom the seabed. Operators want to minimize

expense at this stage in the life of the well, so

cost remains a large concern.

One of the first major subsea well-abandon-

ment projects carried out in the North Sea was for

the Argyll field in the UK sector.14 In 1975, the field,

in 260-ft [79-m] water depth, had been the first to

begin production in the North Sea. By 1992, 35

wells 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. At

that time, conventional abandonment involved

retrieving the completion and setting cementplugs through drillpipe from an anchored or

dynamically positioned semisubmersible drilling

rig. This process would take 8 to 10 days per well.

An innovative alternative proposal called for

squeezing cement into the productive perforations

through the production tubing and cementing the

whole completion into place. This could be accom-

plished in about four days per well with the same

drilling rigs as the conventional abandonment, or


18/54

Winter 1999/2000 19

flushed. The mooring lines, chains and anchors

were moved off-site, and the seven wells were

plugged and abandoned using a combination of

wireline and specially designed coiled tubing

unit. Because the entire abandonment operation

was conducted from the Uncle John, a dynami-

cally positioned semisubmersible, the system

also used an emergency disconnect package.

After the wells were plugged, the subsea trees

and remote templates were retrieved. The flow-

lines and export lines were then filled with

treated salt water and sealed. These lines, along

with the main template, were left in place on the

seabed in such a way that, if required, they could

be used to support future regional development.

What Next for Subsea?

Many companies already are experienced with

subsea solutions and others are just beginning to

become familiar with the advantages and limita-

tions. All agree that although the industry has

achieved measurable advances since the first

subsea well almost 40 years ago, more work hasto be done before subsea technology can be

applied everywhere it is needed.

Nearly all of the current limitations are

related to the extreme depths and operating con-

ditions encountered by subsea wells. One broad

category of work to be done concerns metallurgy.

Embrittlement of metals at subsea temperatures

and pressures causes failures in equipment.

Going deeper may require completely new types

of materials.

Another area of investigation addresses

risers, moorings and umbilicals. Groups are

looking into assessing induced vibrations ondrilling risers and the possibility of developing

polyester moorings.

Elsewhere, other initiatives have been under

taken. PROCAP2000 in Brazil supports the

advancement of technologies that enable produc

tion from waters to 2000 m [6562 ft] depth. Since

its inception in 1986, many of the groups targets

have been reached, but several subsea projectsconcentrating on subsea multiphase flow meter

ing, separation and pumping are continuing.

The Norwegian Deepwater Programme was

formed in 1995 by the deepwater license partici

pants on the Norwegian shelf, including Esso, BP

Amoco, Norsk Hydro, Shell, Saga and Statoil. The

goal was to find cost-effective solutions to deep

water challenges and included acquiring weathe

and current data, constructing a regional mode

of the seabed and shallow sediments, determin

ing design and operational requirements, and

addressing problems related to flowlines, umbili

cals and multiphase flow.17These joint efforts have been established no

with just subsea technology in mind, but to

uncover solutions for exploration and production

in deep water in general. However, many opera

tors are choosing subsea as their long-term

deepwater development concept. By some esti

mates, 20% of the global capital investments in

offshore field developments are in subsea facili

ties and completions.18 This percentage is likely

to rise, especially as subsea equipment contin

ues to prove reliable, flow-assurance problems

are solved and operators gain confidence in sub

sea practice. LS

One of the ways the industry is looking for

innovation is through consortia, initiatives and

joint efforts. One of these, DeepStar, is a group of

Gulf of Mexico participants from 22 oil companies

and 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 is

flow assurance. Paraffins and hydrates are the

main causes of flow blockage in long tiebacks. If

ways could be found to combat their deposition,

longer tiebacks could be possible and economic

thresholds could be lowered, allowing develop-

ment of reserves that are currently marginal.

Several companies are working on solutions

to these problems. Some are proposing and try-

ing methods that attempt to unclog flowlines

with coiled tubing-conveyed tools. Others are

testing the feasibility of heating pipe to control

paraffin and hydrate formation. In addition, theDeepStar organization has begun construction of

a field-scale test facility in Wyoming, USA. The

5-mile [8-km] flow loop will be used to validate

hydrate-prediction software and multiphase flow

simulators, test new hydrate inhibitors, observe

the initiation of hydrate plugs, evaluate sensors

and understand paraffin deposition. Much more

work is needed to ensure that subsea wells and

long tiebacks can sustain flow.

As more provinces mature and prolific fields decline, operators

must contend with subsea well abandonmentas 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 andCollie IA: An Innovative Approach to Argyll FieldAbandonment, paper SPE 26691, presented at theSPE 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 Petroleum

Engineer International 72, no. 5 (May 1999): 54-56.17. Silverman and Bru, reference 16.

18. Thomas, reference 6.


19/54

Nothing lasts forever. To many of us, forever is

our life span, which can vary widely among indi-

viduals. The permanence of inanimate objects

also varies in absolute time and importance. For

example, commercial communication satellites

are expensive to fabricate, difficult to deploy and

generally inaccessible for repair, so it is impor-

tant that they function properly for a long time.

Replacement valves and pacemakers for human

hearts can be replaced or repaired, but not with-

out considerable risk to the recipient. Equipmentsent to the remote research stations of

Antarctica is expected to stand up to harsh con-

ditions. Buildings, bridges and monuments are

also built to endure, but they have finite life-

times. Intelligent completions, which combine

production monitoring and control, are becoming

more common, and require reliable downhole

gauges and flow-control valves.1

Downhole equipment in the oil field also

must stand the test of time. The productive life

of an oil or gas well may be 10 or more years, so

permanent downhole equipment must last at

least that long to satisfy operators expectations.

Because it is impractical to conduct equipment

tests of such long duration, reliability engineer-

ing and failure testing have become mainstays of

those people who develop permanent monitoring

systems. The result has been an impressive

reliability track record for permanent monitoring

installations worldwide.

In this article, we begin by examining thechallenges in permanent monitoring. Next, we

consider how engineers develop robust perma-

nent gauges to provide a continuous stream of

data for the life of a well. Finally, we present

examples that demonstrate how the use of per-

manent gauges adds value by helping to optimize

production and forewarning operators of prob-

lems so that preventive or corrective action can

be taken.

FloWatcher, NODAL, PQG (Permanent Quartz Gauge),PressureWatch, PumpWatcher, Sapphire and WellWatcher

are marks of Schlumberger.1. For more on flow-control aspects of intelligent

completions: Algeroy J, Morris AJ, Stracke M,Auzerais F, Bryant I, Raghuraman B, Rathnasingham R,Davies J, Gai H, Johannessen O, Malde O, Toekje Jand Newberry P: Controlling Reservoirs from Afar,Oilfield Review 11, no. 3 (Autumn 1999): 18-29.

20 Oilfield Review

Downhole Monitoring: The Story So Far

Joseph Eck

Houston, Texas, USA

Ufuoma Ewherido

Jafar Mohammed

Rotimi Ogunlowo

Mobil Producing Nigeria Unlimited

Lagos, Nigeria

John Ford

Amerada Hess Corporation

Houston, Texas

Leigh Fry

Shell Offshore, Inc.

New Orleans, Louisiana, USA

Stphane Hiron

Leo Osugo

Sam Simonian

Clamart, France

Tony Oyewole

Lagos, Nigeria

Tony VenerusoRosharon, Texas

For help in preparation of this article, thanks to FranoisAuzerais, Michel Brard, Jean-Pierre Delhomme, Josiane

Magnoux, Jean-Claude Ostiz and Lorne Simmons, Clamart,France; Larry Bernard and David Lee, Sugar Land, Texas,USA; Richard Dolan and Brad Fowler, Amerada HessCorporation, Houston, Texas; David Rossi and Gerald Smith,Houston, Texas; John Gaskell, Aberdeen, Scotland; andYounes Jalali and Mike Johnson, Rosharon, Texas.

We thank Philip Hall, Chief Executive of The Sir HenryRoyce Memorial Foundation, for information about SirHenry Royces bumping test machine.

Reservoir monitoring requires dependable downhole data-acquisition systems.

Products based on sound reliability engineering and failure testing, essential to

building durable permanent monitoring systems, are responsible for an impressive

track record for permanent gauge installations worldwide. Gauges supply data

useful for both short-term troubleshooting and for long-term development planning.


20/54

Winter 1999/2000 2


21/54


22/54

Winter 1999/2000 23

Dependability, the Sine Qua Non

A basic permanent downhole gauge consists of

sensors to measure pressure and temperature,

electronics and a housing (previous page, right).4

A mandrel on the production tubing holds the

gauge in place. A cable, enclosed in a protective

metal tube, is clamped onto the tubing. The cable

connects the gauge to the wellhead and then to

surface equipment, such as a computer or control

system. Because acquiring and transmitting good

data depend on proper functioning of each part,

such systems are only as reliable as their weak-est component.

A complete monitoring and communication

system, such as the WellWatcher system, han-

dles diverse sensors, including a FloWatcher

sensor to measure flow rate and fluid density

a PumpWatcher sensor to monitor an electric

submersible pump and a PressureWatch gauge

to measure pressure and temperature (below)Surface sensors measure multiphase flow rate

and pressure and detect sand production. In

addition to surface controls for valves and

chokes, there is a computer to gather data, which

Surface sensors and controls Multiphase flow rate Valve and choke control

Pressure measurements

Sand detection

Permanent downhole sensors FloWatcher sensor to monitor flow rate

and density

PumpWatcher sensor

to monitor electric

submersible pump

PressureWatch gauges

to measure pressure and temperature

Host server and database

Data-retrieval and

communications softwareIntegrated

applications

>A complete permanent monitoring system for measuring pressure, temperature, flow rate and fluid density downhole. Surface sensors measureflow rate and pressure. A data-retrieval and communications system facilitates data transfer to the of fice of the end user.

1986Introduction of quartzcrystal permanent pressure

gauge in subsea well

1990Fully supported copperconductor in permanent

downhole cable

1993New generation ofquartz and sapphire crystal

permanent gauges

1994PQG Permanent QuartzGauge performance substant-

iated by gauge accreditationprogram at BP. Start of long-

term lab testing

1994FloWatcher installationfor mass flow-rate measurement


23/54

are stored at the wellsite or transmitted to the

office (below).5

Permanent downhole systems must be

dependable throughout their lifetimesthey

must be reliable and stable. Dependabilitycon-

jures different meanings for different people, but

is used in this article to refer to the combination

of reliability and stability. Reliabilityin the con-

text of downhole gauges refers to proper instal-

lation and ongoing delivery of data from the

gauge. It can be defined as the probability that

the gauge will perform as specified without fail-

ure for a certain amount of time under the

required environmental conditions.

Stabilityrefers to the actual measurement.

Measurements from an unstable or excessively

drifting gauge might prove more troublesome to

an oilfield operator than outright failure of the

gauge. It is important to know whether gradual

variation in a measurement with time indicates

an actual change in the reservoir or reflects a

drift problem with the measuring device.

To ensure a dependable product, it is essen-

tial to maintain strict quality control throughout

the entire engineering process. Quality is the

degree to which the product conforms to specifi-

cations. To truly achieve world-class reliability

and stability entails systematic product develop-

ment and qualification testing, use of qualified

components and proven design methods, strict

audits and tracking of generic parts, failure analy-

ses and consultation with industrial and academic

peers. Reliability and stability cannot be tested

into a product after it is built, but instead must be

considered throughout the entire process, from

design and production to installation.

The Road to Reliability

During the past 10 years, Schlumberger has

enhanced the dependability of its permanent

monitoring systems through improvements in

engineering and testing processes, system

design, risk analysis, training and installation

procedures (next page, top).6 Like other tools and

systems developed by Schlumberger, permanent

gauge development follows a logical sequence of

engineering phases. Dependability concerns are

paramount during each phase.

The engineering phase begins with develop-

ment of a mission profile, or a verbal description

of the technical concept that serves as an engi-

neering framework. The mission profile defines

the role of each component and the environmen-

tal conditions components will encounter during

24 Oilfield Review

WellWatcher

acquisition unit

Sensors

Automatic

data-

retrieval

server

Automatic data-

retrieval client

Central storage

Central storage

configuration

Archiving

database

ASCII files

Data browser

Data access library

Engineering

offices

H E L I K O P T E R S E R V

Wellsite Office

>Data flow. Measurements are transmitted from the downhole device through the cable to surface. The surface data-acquisition unit can send data bysatellite to engineering offices, where data are stored in a library for easy access.


24/54

Winter 1999/2000 25

their expected lifetime. All components of the

system are screened and qualified to withstand

the expected conditions. Accelerated destructive

tests subject components to conditions much

more extreme than expected over their lifetime,

such as greater mechanical shocks and vibrations

and higher-than-downhole temperatures and

pressures. This type of testing helps determine

failure causes and failure modes. Long-term test-ing of the system enables engineers to validate

reliability models and quantify measurement

stability (below).

A drawback to accelerated testing is that

failure can occur simply because of the stressful

test procedure, and the test might not be a good

predictor of actual performance. It is impossible

to test everything, but it is important to test as

much as possible to increase confidence that the

product will perform as required in commercial

operations. Feedback from field engineers is a crit-

ically important complement to laboratory testing.

Product engineering

Mission profile and requirements

Prototype product design

Risk analysis and test plans

Components qualification testing

Reliability qualification testing

Technical reviews and audits

Sustaining, product improvement

Training and personnel development

Training with development and

field engineers

Well completions installation training

Performance evaluation and growth plan

Technique improvement

Project engineering

Reservoir engineering and production

requirements

Well completions design and

installation planning

Well construction, installation and

operation

Project improvement

Reliability and data qualitymanagement

Collect field track records into database

Analyze results and feedback for

improvement

Review with operators, development and

field engineers

>Permanent monitoring system development. From the initial mission profile to failure analysis, collaboration between engineers, field personnel andoperators contributes to continual improvements in permanent monitoring systems.

Permanent gauge stability test. This plotof pressure versus time represents testingof a PQG Permanent Quartz Gauge system atelevated pressures and temperatures for morethan two years. The initial test conditions were140C [284F] and 7000 psi [48.2 Mpa]. Testingwas then accelerated, with the temperatureincreased to the maximum rated temperatureof 150C [302F], and then to 160C [320F] and

170C [338F], to make the gauge fail. Eachtime the temperature was increased, therewas a brief period of measurement drift beforethe gauge reached stability. The gauge driftedless than 3 psi/yr [20 kPa/a]. During the test,the gauge performed as expected, but the testcell had to be repaired twice!

5. For a related article on data delivery in this issue: Brown TBurke T, Kletzky A, Haarstad I, Hensley J, Murchie S,Purdy C and Ramasamy A: In-Time Data Delivery,Oilfield Review11, no. 4 (Winter 1999): 34-55.

6. Veneruso AF, Sharma S, Vachon G, Hiron S, Bussear Tand Jennings S: Reliability in ICS* IntelligentCompletions Systems: A Systematic Approach fromDesign to Deployment,paper OTC 8841, presented atthe 1998 Offshore Technology Conference, Houston,Texas, USA, May 4-7, 1998.

0

10,000

10,005

10,010

10,015

10,020

10,025

10,030

100 200 300 400 500 600 700 800 900

PQG

pressure reading

1 year 2 years

Testcellrepairs

Testcellrepairs

-3 psi/year drift

0 psi/year drift

Duration of testing, days

Pr

essure,

psi

150C 160C 170C

PQG Stability Test at 10,000 psi

>


25/54

Tests for susceptibility to mechanical shock

and vibration, such as those expected during

transport and installation, are also performed.7

These tests are similar in concept to those

developed by Sir Henry Royce, the engineer

behind the success of the Rolls-Royce auto-

mobile. By repeatedly bumping the car on an

apparatus that simulated bumps in a road,

Royce determined which parts of the chassis

were not strong enough and developed better

ones (right).8 The changes included replacing

rivets with bolts and using a few large bolts

rather than many small ones.

In the system-design phase, engineers ensure

proper interfacing between the completion

components. Communication with completion

engineers and third-party vendors has resulted in

continual improvement in downhole cable con-

nections and protection of the system.

Both experts and end users provide input dur-

ing the development phase, as engineers perform

simulations and build mock-ups. Conducted fre-

quently, design reviews include field personnel.Design rules have been prepared to address the

need for low stress on components, minimal

external connections and other concerns.

Once the system is built and is ready for

installation, a specially trained crew reviews

detailed installation procedures and project

plans with operations personnel and third-party

vendors. Performance of the field installation

crew plays an important role in system reliability,

so formal training programs for both system

design engineers and field installation techni-

cians are conducted. Whenever possible, system

design engineers attempt to simplify installationrequirements because factors such as frigid

temperatures, gusty winds and long hours may

present additional challenges to the crew. A

design that allows fast, easy installation relieves

some of the burden on the field crew and

minimizes risk and rig time.

26 Oilfield Review

>Torturing tools. By exposing an automobile chassis to repeated mechanical shocks ( top), Sir HenryRoyce observed which parts were prone to failure and built better ones for Roll-Royce, beginningaround the turn of the last century. Today, highly specialized testing machines and accelerated testtechniques developed by Schlumberger verify the endurance of downhole equipment againstmechanical shocks (bottom).

7. Veneruso A, Hiron S, Bhavsar R and Bernard L:Reliability Qualification Testing for PermanentlyInstalled Wellbore Equipment,abstract submitted to the2000 SPE Annual Technical Conference and Exhibition,to be held in Dallas, Texas, USA, October 1-4, 2000.

8. We thank Philip Hall for information about the bumpingtestmachine. Mr. Hall retired from Schlumberger after22 years of service, both in the oilfield and in electronics.

He is Chief Executive of The Sir Henry Royce MemorialFoundation, The Hunt House, Paulerspury,Northamptonshire, NN12 7NA, England.


26/54

Winter 1999/2000 27

Learning from Experience

If a permanent downhole gauge fails, engineers

analyze the circumstances and sometimes

attempt to reproduce the failure modes in the

engineering center or other testing facility. Failure

mechanisms are not random; in most cases there

are underlying causes at work that must be

uncovered, such as design problems, faulty mate-

rials or improper installation. Schlumberger has

established an on-line database to capture data

about system installations, including details

about environmental conditions, to identify any

patterns in failures (right). The database allows

statistical analysis of the data by region, operator,

environmental conditions and other operational

parameters. Careful analysis of the worldwide

database increases confidence that the appropri-

ate lessons are learned from field experiences

and helps focus efforts on possible areas of

improvement.

From August 1, 1987, to the present, the per-

formance of 712 permanent gauge installations

has been tracked. The oldest system is more than16 years old, having been installed a few years

before the database was established. Analysis of

572 new-generation digital technology installa-

tions made since their introduction in March

1994 indicates that over 90% of these

PressureWatch Quartz and Sapphire systems

were still operating after 2.5 years (below). The

analysis, based on methods introduced by

>Permanent downhole gauge database. Careful tracking of each system enables analysis gauge performance. Comparison of environmental conditions helps teams prepare to instagauges in new locations by learning from past experience in similar areas.

00.0 0.5 2.01.51.0 2.5 3.0 4.0 4.53.5 5.0

10

20

30

40

50

60

70

80

90

100

Operational life, years

Survivalprobability,

%

Permanent gauge operating life. Since record-keeping began in 1987, Schlumberger has installedmore than 700 permanent gauges worldwide.Analysis of 572 new-generation digital technologyinstallations made since March 1994, shown by

the purple line, indicates that over 88% of thesePressureWatch Quartz and Sapphire systemswere still operating after 4 years. The lavendertrend line begins at 97% and decreases by 3%per year, a higher failure rate than that of theactual data. The photograph shows the productionfacilities of the Baldpate field, operated byAmerada Hess.

>


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Mltoft, helps reveal the key factors influencing

the reliability of permanent monitoring systems

(above right).9 The Mltoft method addresses a

systems actual operational time rather than its

calendar time, a key advantage when studying

field installations over a long time period. The

method helps pinpoint areas for improvement in

system design and deployment.

Operating companies have independently

studied the reliability of permanent gauges.10

Different manufacturers and operators measure

performance according to their own standards.

Schlumberger has chosen to focus on the whole

system rather than a single component because

it is vital that the entire system operate properly

and provide usable data.

Downhole to Desktop: Using the Data

After the equipment has survived the ordeal of

testing and installation, the real challenge begins

once a permanent monitoring system is placed

securely in a well. A system that takes a mea-

surement every second of the day produces over31 million data points per year. Coping with the

volume of data from permanent monitoring

systems is an issue that operators and service

companies continue to address.11 Some operators

have chosen to sample their data at specific

times or when the change in a measurement

exceeds a predetermined threshold. Others sam-

ple their data at greater time intervals, such as

30 seconds, to reduce data volume.

Once reaching the end user, the data are applied

to two general production issues: reservoir

drainage and well delivery (right). Reservoir-

drainage aspects include pressure monitoring,pressure maintenance, material-balance models

and simulation models. Well-delivery issues,

such as skin and permeability, affect production

engineering.

When a well is shut in for maintenance, a

pressure gauge offers the small-scale equivalent

of a pressure buildup test. Subsequent well shut-

ins allow engineers to analyze the repeatability

28 Oilfield Review

Reservoir drainage

Application Description

Well delivery

Application Description

Pressure monitoring Static bottomline pressure survey

Pressure maintenance Future development plans (reservoir

repressurization: install injection facilities?)

Real-time fracturing and stimulation

operation monitoring

Appraisal of injection and production

profile along the well

Mater ia l balance model updat ing Input data for cont inuous update and

refinement of material balance model

Well test interpretation and analysis

(buildup, drawdown, multirate and

interference well testing)

Reservoir boundaries, well spacing

requirements, interwell pressure

communication

Water and gas injection monitoring Evaluate degree of pressure support

from injector wells

Appraise performance of injection program

Reservoir simulation model

refinement and validation

Historical database for pressure

history matching

Calibration tool for simulation model

Well test interpretation and analysis

(buildup, drawdown, multirate and

interference well testing)

Skin, permeability and average

reservoir pressure

Production engineering Input for NODAL analysis

Productivity Index (PI) and long-term

variation in PI measurement;

generation of water, gas and sand

production rate correlation as a

function of pressure

Flowing bottomhole pressure survey

to determine maximum offtake

_

Flow well at optimal pressure above

bubblepoint pressure to avoid

liberation of free gas

Complement or corroborate other

reservoir monitoring measurements

Corroboration of information provided

by innovations such as 4D seismic

surveys, time-lapse well logging

>Typical applications of permanent downhole gauge data. Data from downholegauges can be used to improve both reservoir drainage and well delivery.

Operational time

Accumulatedfailures,

%

Flaws(manufacturing and installation related)

Random overload(design related)

Predictablewear-out(design and environment related)

Characterizing performance over time.Even the most reliable permanent gauge canfail and the root cause often is a matter ofspeculation. Production-related or installationflaws account for many early failures. Atintermediate stages, failures occur at a low,relatively steady rate, apparently because ofrandom overloads. After many years of service,failures may occur as components age.

>


28/54


29/54

above and below salt. The first gauge was

installed in September 1997, and to date all of

the gauges continue to operate without failure.

Permanent downhole pressure gauges fulfill

two major requirements for Shell Offshore: daily

operations improvements and better long-term

reservoir management. In both cases, pressure

data must be accessible to reservoir specialists

in a format they can use efficiently. The system

installed by Schlumberger stores the data for

subsequent pressure transient analysis. Shell

Offshore retrieves the data from the system and

uses its own computer-assisted operations (CAO)

system to manage the data stream on a long-

term basis.

Shells CAO acquisition unit captures surface

and downhole pressure measurements at

approximately 30-second intervals for trend analy-

sis and long-term archiving of pressure data. In

the past, most decisions about daily operations

were made on the basis of surface pressure or

tubing pressure measurements with infrequent

downhole wireline pressure measurements. Adecline in surface pressure could indicate reser-

voir depletion or a downhole obstruction, but this

ambiguity could not be resolved with surface

data alone. Now, with both surface and down-

hole pressure measurements, it is possible to

quickly diagnose production problems. For exam-

ple, if both surface and bottomhole pressure

curves track each other on a declining trend, then

the probable cause is reservoir depletion. On the

other hand, if the surface pressure is dropping

but the downhole pressure remains constant or

increases, then the engineer might suspect that

salt, scale or paraffin is plugging the tubing(right).13 Therefore, engineers for the Enchilada

area use surface and downhole measurements to

diagnose production problems and optimize

remediation treatments.

Permanent downhole pressure gauges are

especially important for effective reservoir man-

agement in the Enchilada area and areas like it.

Thin-bedded reservoirs, such as turbidite sands,

can be difficult to evaluate by wireline methods.

Producers want to determine if the reservoir is

continuous. During the initial development, few

appraisal wells had been drilled and the subsalt

location of several prospects made it difficult to

define the reservoir geometry and extent.

Gathering early reservoir pressure data from

each well aided development planning. In addi-

tion, the long-reach, S-shaped wells in the

Enchilada area are expensive to drill and not

easily accessed by wireline methods.

Furthermore, the mechanical risk of running

wireline pressure devices into these high-rate

wells is unacceptable. Therefore, the perma-

nent gauge system allows frequent reservoir

pressure monitoring without mechanical risk

and with minimum deferred production.

Frequent pressure measurements help optimize

production rates, and enhance understanding of

ultimate reserve potential.

The Enchilada area example affirms that data

from permanent gauges are valuable throughout

the life of the well. Run time is a major concern for

Shell Offshore because the Enchilada wells are

expected to produce for at least 10 years. The reli-

ability and durability of these permanent gauges

have a direct impact on the assets value. The suc-

cessful application of permanent monitoring tech-

nology convinced Shell to install gauges in two

wells on their deepwater Ram-Powell platform,

offshore Gulf of Mexico. The second of these

installations, a PQG Permanent Quartz Gauge sys-

tem set at a depth of 23,723 feet [7230 m], is the

deepest installation by Schlumberger to date.

30 Oilfield Review

Pressure

Time

Psurface

Pbhp

Psurface

Pbhp

Pressure

Time

Diagnosing production problems. Plots of bothbottomhole, Pbhp, and surface pressure, Psurface,versus time help engineers diagnose productionproblems. In the top example, surface andbottomhole pressures are declining, but thecurves track each other, suggesting reservoirdepletion. In the bottom plot, the surface

pressure diverges and drops at a faster ratethan the bottomhole pressure. One possibleconclusion is that scale is plugging theproduction tubing.

>


30/54

Winter 1999/2000 3

Complicated deepwater developments, such

as the Baldpate field in Block 260 of the Garden

Banks area of the Gulf of Mexico, challenge oper-

ating companies (above). The first downholegauge in the Baldpate field was installed in

August 1998. Seven of eight wells have down-

hole gauges. The field is expected to produce for

6 to 10 years.

Baldpate field comprises two major Pliocene

reservoirs at depths of 15,500 to 17,500 feet

[4724 to 5334 m]. Original reservoir pressures

exceeded 13,000 psi [89.63 MPa]. Production

from the sands in the Baldpate North area i

Documents

Oil Field Review Winter 1999 English