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Systems in action

The Magnus field, the most northerly producing

field in the UK sector of the North Sea, was being

developed with paired producer and injector wells

operated on voidage. The reservoir had a bubble-

point pressure of 6,350 psi [43,781 kPa] and an initial

reservoir pressure of 7,200 psi [49,642 kPa]. The well

was producing 13,000 bbl/d with an 85% water cut.

To avoid problems related to gas blocking, the res-

ervoir needed to be operated above the bubblepoint.

To control the pressure and optimize production from

 the well, the surface choke needed to be adjusted

weekly. The operator decided that a permanent

downhole monitoring system would help manage

production more accurately and in real time.

A WellWatcher* permanent quartz gauge was

installed in the well at a true vertical depth of

approximately 300 m [984 ft] above the top of the

perforations. The accurate measurements allowed

 the operator to precisely adjust the production choke

weekly to draw down the well to a pressure that

was much closer to the bubblepoint. As a result, the

operator was able to safely maintain the downhole

flowing pressure closely above the bubblepoint,

avoiding any risk of gas blocking. In addition, the

lower drawdown pressure allowed the production

rate to increase by more than 3%.

A subsea tieback was producing from a salt dome

high-relief structure in the North Sea. The operator

needed to obtain accurate information on flow alloca-

 tion per well and to properly manage the drawdown.

WellWatcher permanent pressure gauges in eachwell and a subsea multiphase flowmeter were

installed to acquire continuous downhole pressures

and to measure the flow rate at the subsea level. The

flowmeter provided well pressure data that helped

 the operator understand the production allocation of

individual wells. The flowmeter also monitored and

alerted the operator when the water cut rose by more

 than 1%. The downhole pressure data were used

 to control drawdown on the formation and better

manage watercut and, ultimately, meet production

quotas. Results from pressure buildup tests and

associated analyses conducted during planned

shutdowns helped the operator more accurately

characterize the reservoir and the productivity

of the individual well. The operator continued to

monitor production data through a secure Web

portal and automatic alerts for potential shortfalls

in well productivity.

WellWatcher Permanent DownholeReservoir and Production Monitoring

MANAGING THE RESERVOIR

DRAWDOWN EFFICIENTLY

ACHIEVING ACCURATE PRODUC-

TION ALLOCATION IN A SUBSEA

FIELD AND SUCCESSFULLY

MANAGING THE DRAWDOWN

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www.slb.com/wellwatche

WellWatcher Permanent Downhole Monitoring

*Mark of Schlumberger

Copyright © 2008 Schlumberger. All rights reserved. 08-CO-302

Two platform wells offshore Dubai were producing

gas through a single multiphase flowmeter via amanifold. One well was moderately deviated and

segmented and was equipped with an intelligent

completion. The other well was highly deviated and

producing from the field. Flow control valves con-

 trolled the production from two sand channels. The

operator needed to know the flow contribution from

each zone. Because the production platform gas-

handling capability was constrained, proper control

of the gas/oil ratio was also necessary.

The wells were equipped with WellWatcher dis-

 tributed temperature sensing (DTS) systems along

 the producing intervals to monitor their temperature

profiles. The temperature profile measurement in

 the intelligent completion well provided informationfor zonal allocation and gas detection. The tempera-

 ture profile measurement enabled the operator to

make informed decisions on actuating the sleeves.

In the highly deviated well, the DTS measurements

enabled the operator to identify gas entry points and

 to discretely quantify the volumes produced through

multirate testing. For both wells, gas production

characterization allowed the operator to precisely

manage and quantify gas production within the

platform capability.

The Rang Dong field offshore Viet Nam includes

lower Miocene and basement reservoirs. The base-

ment reservoirs are fractured and have bottomhole

 temperatures as high as 153 degC [307 degF]. The

high-temperature environment made managing

 the complex reservoir a challenge for an operator.

Field development planning required continuous

permanent downhole pressure monitoring over

several years. The operator needed a monitoring

system that was both accurate and highly reliableat high temperatures.

Permanent WellWatcher gauges were installed

in all of the basement wells and in 25% of the

lower Miocene wells. Pressure and temperature

data enabled the operator over time to clearly

understand the fractured reservoirs. Reservoir

pressure measurements, vital for history matching,

were continuously monitored. As a result, reservoir

characterization was greatly improved, and

continuous production was optimized. Capital

expenditures were significantly decreased because

of the reduced production downtime, and comple-

 tion integrity was enhanced. Health, safety, and

environmental events were minimized. In addition, the bottomhole data played an important role in

helping the operator assess and optimize subse-

quent field developments.

OPTIMIZING PRODUCTION FROM

COMMINGLED RESERVOIRS BYCONTROLLING GAS PRODUCTION

MANAGING A HOT, FRACTURED,

AND COMPARTMENTALIZED

RESERVOIR