This year, A&A Consulting Team of seasoned consultants has taught the popular course on ‘Practical Aspects of CO2 Flooding EOR’ at 2018 SPE ATCE in Dallas, Texas, on September 27, 2018, at 2018 SPE IOR Conference in Tulsa, Oklahoma, on April 15, 2018, and at 2018 SPE EOR Conference in Muscat, Oman, on March 25, 2018.

This popular course or expanded customized versions of it have now been taught 26 times, at 15 locations around the world (Abu Dhabi, Anaheim, Barcelona, Buenos Aires, Dallas, Denver, Florence, Houston, Jackson, Midland, Muscat, New Orleans, Rio de Janeiro, San Antonio, and Tulsa).

The customized state-of-the-art training courses and workshops are designed and developed by A&A Consulting Team of seasoned consultants at the request of A&A clients, and are taught or conducted at their offices, around the world, whenever mutually convenient.

There is a significant opportunity for CO₂ flooding of depleted oil reservoirs along the Gulf Coast of Texas and Louisiana.  Louisiana salt dome fields have high API gravity oil and are deep enough that miscibility can be achieved.  There are 33 fields which have produced over 100 million barrels of oil and many of these fields are nearing depletion and can be acquired at low cost.  There are also a significant numberof industrial plants which are emitting CO₂ and can provide the necessary supply of CO₂ to inject.  The Phillips 66 Alliance Refinery in Belle Chase, LA, emitted 122 MMCFPD of CO₂ during 2016.  The Big Cajun 2 plant in New Roads, LA, emitted 279 MMCFPD of CO₂ during 2016 and could have the capacity for 589 MMCFPD based upon EPA reporting.  There are 33 fields which have produced over 100 million barrels of oil in South Louisiana.  The State of Louisiana waives the 12.5% severance tax on EOR projects until payout, and in the State waters they may waive the State royalties until payout.  This provides an enormous incentive to conducting EOR.

Texas Gulf Coast Opportunities

The Gulf Coast of Texas also offers a significant opportunity for CO₂ flooding conventional reservoirs, such as the salt dome and barrier island fields in the Miocene, Frio, and Wilcox sands.   Very high cumulative production has been made in the Bay City, Bryan (Woodbine), Conroe, East Texas, Hastings, Magnet Withers, Manvel, Thompson, Tom O'Connor, Webster, and West Ranch fields to name a few. 

The unconventional development of the Eagleford shale could, perhaps, offer the greatest potential for CO₂ flooding.  This area south of San Antonio extends for approximately 200 miles and has incredible oil production.  Avasthi & Associates, Inc. (A&A) can analyze this formation to look at the impact of imbibition with water injection and potential EOR reserves using CO₂.  There are a significant number of industrial sources of CO₂ along this trend which can be used for injection.  With oil recoveries of less than 10% OOIP, a large target exists.

A&A can help your organization determine potential candidates for CO₂ flooding and locating CO₂ supplies which may be available.  We would be happy to discuss these opportunities with you.

Avasthi & Associates, Inc. (A&A) is state-of-the-art EOR/IOR consulting company, helping its clients, around the world, improve production rates and recoveries, and project profitability, from their oil & gas fields, and unconventional/ shale resources. 

Much has been written about revitalizing mature oilfields. Everyone gets lucky now and then by finding a bypassed oil zone that has not been perforated and as a result sizeable oil production is obtained. The production from these zones, however, is often short-lived due to the limited pay.

The high-level and seasoned consultants of A&A Consulting Team have worked for many years extracting the last economic barrel from mature/marginal oilfields, and can quickly identify if the field has good potential or not. A&A consultants have also developed some unconventional techniques that may extend the life of the field considerably. These methods can be characterized as: (1) plug down and run pulsed neutron or carbon/oxygen logs to look for bypassed oil, (2) maximize fluid recovery through use of gas lift or submersible pumps so that economic production can be achieved by maximizing fluid production, and (3) inject water to raise reservoir pressure and alter the streamlines of production to recover bypassed oil. 

Many wells were plugged back in the 1950s and 1960s, when oil prices were low, yet the well was still producing at good oil rates based upon today's standards. Many operators were also blindfolded by their mode of production (flowing, rod pumping, or gas lifting), and could not consider producing the reservoir at higher withdrawal rates due to the high upfront capital investment required. An operator would also never consider injection of water into a moderately strong waterdrive reservoir to alter the streamlines to flow so that higher oil recovery could be established. At today's oil prices, some of these alternatives are attractive.

The first step to identify the potential of a mature/marginal oil field is to compile good well histories with perforations and production records for each zone. A 20 BOPD producer back in the 1950s or 1960s was unattractive when considering zones further up the hole, but these zones can now provide substantial cashflow. Many wells were plugged back during the early years due to higher anticipated oil and gas production rates from zones above. This resulted in many barrels of bypassed oil, which can now be recovered at these higher oil prices.

The economic conditions of the 1950s and 1960s also often prevented the installation of large gas lift systems or submersible pumps in small fields. This limited the fluid withdrawal rates and reduced the oil percentage, which could be considered economic. By running sand control (if required), and producing the wells at higher rates today, increased oil reserves can be achieved.

While not an obvious method to increase oil recovery from mature oilfields with strong waterdrive, the injection of water into selected wells can alter the flow regimes (streamlines) in the reservoir. A&A consultants have seen this first hand where a strong waterdrive reservoir was subjected to water injection prior to CO₂ injection and higher oil recovery was achieved. The water injection not only raised reservoir pressure, which increased well productivity, but also pushed bypassed oil (due to well spacing) to the producers. The high productivity index of the wells allowed for increased production as reservoir pressure increased, and the water injection pushed oil away from the faults and unswept areas of the reservoir to increase oil production.

The high-level and seasoned consultants of A&A Consulting Team have extensive experience in revitalizing mature/marginal oil fields, and will be delighted to assist you in maximizing oil production rates and reserves from your company’s mature/marginal oil fields. 

Surveillance of CO₂ floods is critical in establishing maximum oil recovery.  Injection and production profiles are used to determine the inflow and outflow of fluids into the various layers of the reservoir.  Radioactive tracer logs are often used for this purpose.  A slug of radioactive tracer (typically Iodine 131) is added to the injection fluid and as the slug moves down the well, several gamma ray logs are recorded at specific time intervals.  The reduction in tracer material as it moves down the wellbore indicates how much of the injected fluid goes into each zone.  The position of the tracer slug is seen as a large gamma ray spike whose size is proportional to the flow rate.  A reduction in the size of the peak indicates a loss of fluid into the formation.  Fluid velocity can also be calculated from the time interval and the distance the peak has moved using time-slug analysis.  The radioactive tracers can be used to detect channels and leaks within the casing and cement jobs.  Correction of these wellbore integrity issues is critical in maximizing vertical sweep.

Tracer logs can also be used to determine inflow from the producing zones.  The tool is operated in reverse mode to that of an injection profile.  Capacitance sensors are installed to determine the percentage of oil and water flow from each zone.  The dielectric constant of water (80) is so high relative to that of oil (1.9 to 2.3) that the capacitance is a direct indicator of the amount of water.

In addition to inflow and outflow from perforations in the wellbore, the breakthrough of CO₂ provides an indication of the sweep.  Dimensionless curves can be generated for the various patterns and poorly performing patterns can be identified.  This deviation from normal flow behavior provides an indication that the injector and producers should be investigated for potential mechanical integrity issues.  The adjustment of injection and production flowrates can also be used to maximize areal sweep based upon the formation thickness and pattern size.

For relatively mature CO₂ floods, 3-D seismic has been used to determine areal sweep.  Operators often do not consider the fact that CO₂ can move downdip toward plugged and abandoned wells.  Should this occur and these wells have mechanical issues, extreme losses of CO₂ can occur.  Reservoir pressure in all parts of the reservoir should therefore be monitored closely.

A&A Consulting Team of high-level and seasoned CO₂ EOR consultants has the expertise and extensive CO₂ EOR project experience to help our clients on all aspects of their CO₂ EOR reservoir surveillance projects in order to optimize production rates and maximize reserves, and to maximize project profitability.

In the US Gulf Coast region, and in many other parts of the world, some of the largest oil reservoirs have strong waterdrive aquifers which assist in maintaining reservoir pressure during primary production. While these aquifers are somewhat infinite, they are insufficient for maintaining pressure at original 'discovery' levels and often the pressure drops below MMP (Minimum Miscibility Pressure). While good oil recoveries have been seen by conducting CO₂ floods below the MMP, it is desirable to pressure up the reservoir as high as possible (above MMP) to achieve maximum oil recovery. A&A consultants have experienced this in actual field demonstrations where reservoir pressure was raised by water injection (SPE #144961-PP- 'Large Scale CO₂ Flood Begins Along Texas Gulf Coast', Presented at 2011 SPE Enhanced Oil Recovery Conference in Kuala Lumpur, Malaysia, 19-20 July, 2011). While doing so, it was found that large volumes of water leakoff into the aquifer during the re-pressurization process, and this can go on for many years at rates as high as 200,000 - 300,000 BWPD in the applicable fields. The design was effective in raising reservoir pressure and reducing the volume of CO₂ purchase, but the cost of water injection was expensive and often required large volumes of make-up water which had to be produced from other water bearing sands. In the case described, a nearby producing offset field also experienced reduced aquifer pressure, thus compounding the problem. All this must be considered while designing CO₂ floods in reservoirs impacted by strong and limited acquifers in the US Gulf Coast region, and in many other parts of the world.

A reservoir type which is often overlooked due to its low reservoir pressure, at the time of CO₂ flood, is the depletion drive reservoir. The depletion drive reservoirs contain higher oil saturations than waterdrive reservoirs and can be pressured-up with CO₂. The salt dome fields in the US Gulf Coast region are ideal candidates for CO₂ flooding as many of the small fault blocks had limited aquifers, and therefore had low oil recoveries during primary production. These small fault blocks were also poor waterflood candidates due to the inability to establish good patterns to improve sweep. Continuous CO₂ injection, on the other hand, offers some clear advantages for maximizing oil recovery from these isolated fault blocks. The reservoir can be pressured-up with CO₂ and then the wells flowed back while recycling the CO₂ to maintain reservoir pressure. The CO₂ moves to the boundaries of the fault block and contacts more oil than what could be achieved by water injection. The key parameters for successful CO₂ flooding of these reservoirs are good fault seal, and  ability to pressure-up the reservoir. Material balance is used during the re-pressurization process to determine pore volume impacted by injection, and if CO₂ leaks into the adjacent fault block this can be accounted for. 

A&A consultants have screened numerous oil fields in the US Gulf Coast region for reservoirs amenable to successful CO₂ flooding, and we can assist your company with screening/ scoping/ feasibility studies, and CO₂ flood project design studies.