8/17/2019 Uisng Soap to Revive Mature Oil Field

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Academia

Most reservoirs in the US under

operation by smal l producers have

become mature due to extended

waterflooding. In fact, an estimated 80%

of the total number of oil wells in the

US are now classified as “marginal.”

The mature reservoirs accessed by

these wells usually have a high water

cut, in the range of 80% to 90%. Also,

the industry typically leaves about

65% of oil behind after many years ofwaterflooding because of reservoir

heterogeneity and incomplete sweep of

the formation.

Excessive water production

becomes a major problem as these oil

fields mature. High volumes of water

 production result in increased levels

of corrosion and scale, increased

load on fluid-handling facilities,

increased environmental concerns,

and eventually well abandonment

(with associated workover costs).

Consequently, producing zones are

often abandoned in an attempt to

avoid water contact, even when the

intervals still retain large volumes of

recoverable hydrocarbons.

Controlling water production has

been a challenging goal for most

oil producers.

Reservoir heterogeneity severely

affects the flow of gas, oil, and water

in the reservoir and thus affects

the choice of production strategies,

reservoir management, and ultimate oil

recovery. Reservoir heterogeneity is

the single most important reason for low

oil recovery, early breakthrough, and

excess water production. To maintain

reservoir pressure, these reservoirs

have usually been developed bywaterflooding from an early stage

in their development. Many of them

have been hydraulically fractured,

intentionally or unintentionally, or have

channels due to mineral dissolution

and production during many years

of waterflooding.

Reservoirs with induced fractures

or high-permeability channels are

quite common in mature oil fields.

Resin, foam, polymer/gel treatments,

and/or polymer flooding are among

enhanced oil recovery (EOR)

techniques typically used to correct the

reservoir heterogeneity and improve

oil production. Chemical EOR (CEOR),

involving alkali, surfactant, and

 polymer chemicals, is currently gaining

some attention in the oil industry to

mobilize and recover large amounts

of both unswept and residual oil from

mature oil fields.

Chemical EOR Challenges

and Recent Advancements

CEOR includes the injection of a

mixture of chemicals to improve sweep

efficiency and produce residual oil

saturation left behind in the swept

 volume. T he follow ing are some of the

barriers to widespread implementation

of CEOR:

1. Uncertainties in reservoir

geology

2. Project logistics

3. High front-end investment and

delay in oil production and payout

4. Complex engineering and the

need for highly specialized staff

5. Some negative field experiences

dating back to the 1980s

However, there have been

several crucial improvements to

increase the widespread application

of CEOR processes. Examples of

these improvements include better

geological description of oil reservoirs;

Using Soap to Revive Mature Oil FieldsMojdeh Delshad, The University of Texas at Austin

Mojdeh Delshad is a research professor in the Department

of Petroleum and Geosystems Engineering at The Universityof Texas (UT) at Austin. She is also the assistant director for

the US Department of Energy-funded Center of Frontiers of

Subsurface Energy Security. Delshad holds a BS degree in

chemical engineering from Sharif University and MS and

PhD degrees in petroleum engineering from UT Aust in. She

has 27 years’ experience in modeling multiphase flow, fluid

 property modeling, and reservoir simulation of enhanced oil recovery processes,

and is in charge of the UT Chemical Flooding reservoir simulator (known as

UTCHEM) development, user support, and tra ining. Delshad was awarded the SPE

rank of “A Peer Apart” for reviewing more than 100 technical papers in 2010. She is

currently a member of the SPE Books Development Committee.

Fig. 1— Example of surfactant

molecule.

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improved reservoir simulation;

horizontal and multilateral wells; more

efficient and better quality polymer

and surfactant molecules that are stable

at higher temperatures and higher

salinities (Fig. 1); new cost-effective

CEOR processes, such as alkaline/

co-solvent/polymer, and the use of

surfactants for wettability alteration in

carbonate reservoirs; and extending

the application of CEOR floods to

higher temperatures and higher

salinities, higher viscosity oils, and

carbonate reservoirs.

Chemical EOR Working

Principles and Associated

Synergism

The way a chemical flood works is

through the synergist ic effect of a

 polymer (to improve mobility by

slowing down the movement of thewater to match that of the oil [i.e.,

mobility ratio of 1]) and a sur factant

(with or without alka line) to reduce the

interfacial tension (IFT) between oil

and water and thereby displace the

discontinuous trapped oil remaining in

the reservoir after the waterflood. Using

a surfactant i nvolves the same concept

as using detergent/soap to remove oil.

The primary objective of surfactant/

 polymer (SP) or alkal ine/surfactant /

 polymer (ASP) flooding is to reduce the

IFT between oil and water to values on

the order of 0.001 dyne/cm or less in

order to displace the trapped oil from

rock pores.

The use of alkaline chemicals for

improving oil recovery dates back

to the 1920s. The alkaline flooding

 process relies on chemical reactions

between alkali, such as sodium

carbonate, and organic acids in the

crude oil to produce in-situ surfactants

(soaps) that can reduce the IFT. Most

researchers of the process have

reported that the lowest IFT occurs

at very low alkali concentrations. On

the other hand, alkali consumption

by the reservoir demanded injection

of a higher alkali concentration. This

 problem was resolved by Nelson

et al. (1984), who proposed a method

to enlarge the low-IFT region andthereby promote optimum salinity by

combining the alkali with a surfactant

which is more hydrophilic than the

in-situ–generated soap. The formation

of the in-situ surfactant also reduced

the need for a synthetic surfactant

in an ASP slug (typically 10) is an indication of ultralow IFT

(