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EQUALIZER technology optimizes production, delays water coning incomplex Russian fieldBy Lukasz Ostrow ski and Eddie Bow en, Baker Hughes

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T he good news is the Verkhnechonskoye green field is the largest oil and gas condensate reservoir yet to be

discovered in eastern Siberia and holds great promise for expanding Russia’s hydrocarbon reserve base. The bad news

is the immense production challenges due to the reservoir’s geologic complexity, the remote location and the lack of

existing infrastructure. To make the Verkhnechonskoye field economically viable, the latest in sand control completion

technology was required to overcome the geologic challenges and to maximize production and ultimate reserve recovery

from the reservoir.

The Verkhnechonskoye reservoir consists of shallow marine

and alluvial sediments. The productive zone is represented

by two Cambrian sandstone layers that range in thickness

from 2.2 to 26 m (7.2 to 85 ft) and 5.5 to 20.2 m (18 to 65.6 ft),

respectively, with an average depth of approximately 1650 m

(5,412 ft). The layers are separated by a gradually narrowing

shale deposit. As a result, both sandstone layers form a

hydrodynamically connected reservoir with a thickness of 2.7

to 22.8 m (8.8 to 75 ft). An alluvial sedimentary environment

implies highly inconsistent and heterogeneous reservoir

parameters.

"Due to the lack of an active aquifer, a water injection system is required to maintain the reservoir pressure," explains

Lukasz Ostrowski, director, completions and reservoir services for Baker Hughes Russia.

"The reservoir oil is saturated, and any reduction in the reservoir pressure is undesirable.

"Although horizontal wells increase drainage area and improve recovery, water and gas tend to cone toward the heel of

the well because of friction pressure drop from toe to heel and breakthrough anywhere in the well because of

permeability variation along the horizontal section."

Baker Hughes' EQUALIZERTM inflow control devices are widely used as a permanent part of the well completion to

control flow from the reservoir to the wellbore along the length of the horizontal section. They manage inflow by applying a

resistance to flow at the reservoir face.

Source: www.cisoilgas.com

© 2012 GDS Publishing Ltd. All rights reserved.

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Choosing the optimal completion design

Using geological data from existing wells, minimum and maximum permeability values from core and well test analysis,

permeability profiles are created. The success of any inflow control device system depends on the accuracy of this

geological information, as permeability distribution along the horizontal section is a key point in completion design.

Using various possible permeability profiles, a well completion design is proposed-including the number of equalizers

and the length of intervals-to effectively equalize the inflow. The main objective of this evaluation stage is to determine

whether a positive effect can be reached using the Baker Hughes EQUALIZER drainage system.

"There is a lot of interest in this technology in these Russian fields, where the biggest challenge is water breakthrough,"

says Eddie Bowen, EQUALIZER product line manager. "Any time there is an oil/water contact, there's the question of

'How do you keep the water at bay as long as you can to maximize reserve recovery?' This technology allows the

operators to do that."

"Initially, the technology is more expensive to run than conventional slotted liners or conventional screens, but we can

illustrate the value of this technology to the client through reservoir modeling before the fact," Bowen adds. In 2007, using

production history and reservoir data supplied by the operator, Baker Hughes provided an initial concept study for

completion and monitoring methodology to alleviate the inflow balance issues in the Verkhnechonskoye reservoir. Based

on the precompletion modeling, Baker Hughes recommended using the EQUALIZER system on two producing wells to

obtain the best value for the operator from this complex environment.

"In our predictive modeling analysis, we took the known permeability variables confirmed through production logging

tests (PLTs), and we determined the best design for these particular wells," Ostrowski explains. "Then, we compared that

to conventional technologies and did some forecasting to show the value of the installation."

Bowen says that an EQUALIZER installation could cost an additional USD 200,000 to USD 300,000 versus a

conventional solution, "but the net present value may be 200 percent." (Net present value [NPV] compares the value of a

dollar today to the value of that same dollar in the future, taking inflation and returns into account. If the NPV of a

prospective project is positive, it is often accepted.)

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Measuring the EQUALIZER system performance

Three wells were completed in this field with the EQUALIZER technology: two producers (No. 1 and No. 2) and one

injector (No. 3). The planned design for the producers included a uniform arrangement of packers and EQUALIZER joints

(seven EQUALIZER joints per each of five zones created with five openhole packers). The design for the injector included

three EQUALIZER joints per each of five zones. The typical completion design is shown in Illustration 1.

After drilling the candidate well, the actual profile of permeability was built based on final logs, and the completion design

was updated. Packer placement depth was selected to isolate high and low permeability. The number of EQUALIZER

joints was determined to mitigate high inflow from high-permeability zones and to allow flow with little completion

resistance for low-permeability zones. Low reservoir temperature required use of Baker Hughes' REPackerTM reactive

element packers that could swell in the given reservoir conditions. After an initial production period, the operator ran

PLTs in each well. Engineers then compared the actual to predicted inflow profiles for the same wells without the

EQUALIZER systems.

The real inflow profile was matched by a simulation model. Based on these models, it was possible to create a complete

inflow profile for an openhole completion. Figures 1 to 3 show the actual inflow profile for the EQUALIZER system well

from PLT measurement (blue), the predicted inflow profile for an openhole well (green) and predicted inflow profile for an

EQUALIZER system well (orange).

"It is important to note that the predicted inflow profile curves for the EQUALIZER system well were calculated only after

final logging and were based on the anticipated liquid rate and pressure drawdown," Ostrowski says. "However, the true

production rates sometimes differ significantly from the predicted rates. The model curve for the openhole completion

was generated based on the actual production data."

The inflow profiles indicate good performance from the EQUALIZER designs in well No. 2 and well No. 3, as opposed to

well No. 1. "In the case of well No. 1, we were unable to construct the appropriate permeability profile due to lack of data.

The actual permeability was lower than anticipated, and, as a result, the EQUALIZER system did not provide any value as

the real liquid rate per EQUALIZER joint is much lower than designed," notes Ostrowski. Even in a field where reservoir

uncertainty is very high, inflow control devices can successfully equalize oil inflow in horizontal wells. "Baker Hughes has

run more than 2 million ft of EQUALIZER technology with zero reported sand failures," Bowen notes. "The keys to

optimizing inflow control device design are accurate field data, especially an accurate permeability profile, and good

reservoir modeling-the exact sort of information we had on these wells in the Verkhnechonskoye Field."

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