Oil & Natural Gas Projects
Exploration and Production Technologies
Improving CO2 Efficiency for Recovering Oil in Heterogeneous Reservoirs
This project was in response to DOE's FY2001 solicitation DE-PS26-01NT41048,
Development of Technologies and Capabilities for Developing Coal, Oil, and Gas
The objective of this project is to increase effectiveness and viability of
CO2 mobility control using foaming systems, to minimize injectivity losses,
and to model these mechanisms.
New Mexico Petroleum Recovery Research Center, (PRRC)
New Mexico Institute of Mining and Technology
Parameters that have been tested for their effects on foam stability include:
salinity, pH, surfactant concentration, surfactant structure (composition),
temperature, pressure, rock type, rock composition, rock structure, and adsorption
and desorption kinetics and equilibrium. Parameters that have been considered
and tested for temporary versus permanent effects on injectivity and productivity
in CO2 IOR injections include: flow rate, contamination, dissolution, precipitation,
Project results will have significant consequences for the future of IOR. Parameters
will be determined that will result in more efficient CO2 flooding in heterogeneous
reservoirs and will include the following benefits:
- Extending the life of the petroleum reservoir, maintaining or increasing
employment, and increasing oil recovery.
- Expanded range of reservoirs amenable to CO2 flooding
- Reduction of chemical cost: optimizing oil saturation tolerance of foam,
decreasing primary foaming agent adsorption, and decreasing required primary
foaming agent concentration.
- Delayed production of CO2 and increased retention of CO2 in the reservoir
- Improved injectivity of CO2 and water,
- Improved CO2 flooding predictions, and
- Decrease in the mobility of CO2 during the alternate injection of brine
CO2 flooding potential has been demonstrated in the US, particularly in the
Permian Basin of west Texas and southeast New Mexico. Much of the research on
CO2 flooding can be applied to other gas flooding processes, such as hydrocarbon
injection projects. Today over 300,000 bbl/day are produced by gas injection
in the US that barely scratches the surface of the 351 billion barrels of remaining
U.S. oil reserve. The potential recovery is at least one order of magnitude
greater with moderate success in developing improved methods, expanding the
use of existing technology, expanding market availability of CO2, and sequestration
Results of previous work have been described in reports to DOE/NPTO, in papers
presented to the Society of Petroleum Engineers, and in other conference proceedings
and refereed publications. A comprehensive review of recent accomplishments
can be obtained from DOE Annual and Final Project Reports and in over 40 publications
on specific topics, including: injectivity, phase behavior and multiphase flow,
pressure effects, mobility control and foam properties, selective mobility reduction,
foam mechanisms, mixed surfactants and sacrificial agents, gravity drainage,
imbibition, interfacial tension, field foam modeling and history matching, numerical
methods, and CO2 reservoir injection studies. The present project is concentrating
on determining the mechanisms of adsorption and desorption of surfactants in
a reservoir, the effects of reservoir conditions on surfactant solution - CO2
foamability, and causes of injectivity changes in CO2 injection systems.
This project attempts to improve understanding of foaming agents and injectivity.
Most of the study will be laboratory-related with supporting modeling and field
liaison projects. The foam study includes the: 1) evaluation of hybrid foam
systems (synergetic effects of multi-component systems), 2) evaluation of low-cost/higher
performance systems, 3) development of transport and adsorption models, and
4) evaluation of mobility improvements for reservoirs with severe heterogeneities.
The injectivity and related flow mechanisms study includes: 1) the review of
field data to assess extent and causes of WAGIL, 2) laboratory tests to identify
mechanisms, and 3) tests to determine the effects of permeability alteration,
contamination, relative permeability, saturation, flow rate, stress, and other
identified parameters. Modeling includes: 1) the determination of sweep mechanisms,
2) hybrid foam flow adsorption and transport, and 3) injectivity. Finally, optimizing
the benefits of using public funds is being achieved by transferring to the
public information of the discoveries and developments of this project through
publications and presentations in public forums.
The following have been achieved:
- Identified properties that affect foaming agent adsorption, i.e.: rock type,
surfactant type, surfactant concentration, co-surfactants, and sacrificial
Identified the synergistic effects on foam in dual chemical systems.
- Determined results affects of salinity, pH, surfactant concentration, cosurfactant
combinations, temperature, and pressure on foam stability.
- Determining causes of injectivity reduction: contamination, fines migration,
permeability changes, stress/pressure gradient, phase behavior, and flow rate
with permeability changes resulting from dissolution and precipitations appears
to be the only permanent change.
Despite favorable characteristics of CO2 for IOR, CO2 floods frequently experience
poor sweep efficiency caused by gas fingering and gravity override, caused by
reservoir heterogeneity, adverse mobility ratio, and low productivity caused
by lower-than-expected injectivity. Poor sweep efficiency results from a high
mobility ratio caused by the low viscosity of even high density CO2 compared
to that of water or oil. The effectiveness of water injection alternating with
gas (WAG), a common process used for mobility control during CO2 floods, is
reduced by gravity segregation between water and CO2 and amplified by permeability
differences. Foaming agents introduced in the aqueous phase control mobility.
However, costs incurred by the loss of chemicals to adsorption on reservoir
rock often exclude this potentially beneficial option for many operators.
The project seeks to develop systems with lower concentrations of good foaming
agents that will reduce cost. These systems are derived using a sacrificial
agent or a cosurfactant that shows synergistic improvements when mixed with
the good foaming agents. As part of this work the adsorption of surfactants
onto common reservoir minerals was studied.
WAG process frequently reduce injectivity more than expected and the addition
of mobility control agents inherently compounds this problem. Normally, improved
mobility ratios will reduce injectivity, and for this purpose it is critical
that we optimize the two effects together. Improved injectivity will also result
from the lower chemical concentrations and through some of the synergistic improvements
using the cosurfactant systems mentioned above. The high flow rates at near
wellbore conditions have been considered as a cause of decreased injectivity.
The gas expansion at and near the wellbore caused temperature reduction and
it appears to have also caused damage with a significant reduction in production.
Current Status (December 2004)
This project is nearing completion. The original completion date was September
27, 2004. A one-year no-cost extension to September 27, 2005 was granted. In
addition to the original goal the extension is allowing for determination of
surfactant sorption properties on five pure minerals common in reservoir rock.
Over the years PRRC has work with DOE's pseudo-miscible reservoir simulator
MASTER and with the extension a copy of PRRCs debugged version of MASTER with
an additional routine for foam flooding will be a deliverable for this project.
Grigg, R.B.: "Improving CO2 Efficiency for Recovering Oil in Heterogeneous
Reservoirs," 1st, 2nd, and 3rd Annual Reports for DOE Contract No. DE-FG26-01BC15364,
U.S. DOE (Nov. 2004) covering Sep. 28, 2001 - Sep. 27, 2004. (Jan. 2003, Nov.
2003, and Nov. 2004).
Grigg, R.B., Zeng, Z., and Bethapudi, L.V.: "Comparison of Non-Darcy Flow
of CO2 and N2 in a Carbonate Rock," SPE 89471, 2004 SPE/DOE Fourteenth
Symposium on Improved Oil Recovery, Tulsa, OK, Apr. 17-21.
Zeng, Z., Grigg, R.B., and Gupta, D.B.: "Laboratory Investigation of Stress-Sensitivity
of Non-Darcy Gas Flow Parameters," SPE 89431, 2004 SPE/DOE Fourteenth Symposium
on Improved Oil Recovery, Tulsa, OK, Apr. 17-21.
Zheng, Z, Grigg, R.B., and Ganda, S.: "Experimental Study of Overburden
and Stress Influence on Non-Darcy Gas Flow in Dakota Sandstone," SPE 84069,
SPE Annual Technical Conference and Exhibition held in Denver, CO, Oct. 5 -
Grigg, R.B, and Svec, R.K.: "CO-Injected CO2-Brine Interactions with Indiana
Limestone," SCA 2003-19, International Symposium of the Society of Core
Analysts, Pau, France, Sep. 21-24, 2003.
Grigg, R.B., McPherson, B.J., and Svec, R.K.: "Laboratory and Model Tests
at Reservoir Conditions for CO2-Brine-Carbonate Rock Systems Interactions,"
The Second Annual DOE Carbon Sequestration Conference, May 5-8, 2003, Washington,
Wellman, T.P., Grigg, R.B., McPherson, B.J., Svec, R.K., and Lichtner, P.C.:
"Evaluation of CO2-Brine-Reservoir Rock Interaction with Laboratory Flow
Tests and Reactive Transport Modeling," SPE 80228, International Symposium
on Oilfield Chemistry, Houston, TX, Feb. 5-8, 2003.
Grigg, R.B., Bai, B., and Liu, Y.: "Competitive Adsorption of a Hybrid
Surfactant System onto Five Minerals, Berea Sandstone, and Limestone,"
SPE 90612 2004 SPE Annual Technical Conference and Exhibition, Houston, TX,
Grigg, R.B., and Bai, B.: "Calcium Lignosulfonate adsorption and desorption
on Berea sandstone," Journal of Colloid and Interface Science, 279 (2004)
Grigg, R.B., Tsau, J-S., and Martin, F.D.: "Cost Reduction and Injectivity
Improvements for CO2 Foams for Mobility Control," SPE 75178, 2002 SPE/DOE
Improved Oil Recovery Symposium, Tulsa, OK, Apr. 13-17.
Project Start: September 28, 2001
Project End: September 27, 2005
Anticipated DOE Contribution: $999,947
Performer Contribution: $499,974 (33% of total)
NETL - Paul West (email@example.com or 918-699-2035)
PRRC NMT - Reid Grigg (firstname.lastname@example.org or 505-835-5403)
Relative adsorption of two surfactants CD 1045 (a good foamer) and a calcium
lignosulfonate (a sacrificial agent) onto five minerals.