While EOR has played an important role in U.S. onshore production, during times of extended low prices, it becomes more important than ever because, if planned well, the costs per barrel recovered can be quite low. Welcome to an interview with Jesse Garnett White and Mike Raines, whose focus has been on determining the best ways to recover some of the previously unrecoverable oil and gas from mature fields.
What are your names, backgrounds, and prime focus these days?
Jesse Garnett White.
My name is Jesse Garnett White. I am a professional petroleum geologist with a B.S. in Geology from the University of Idaho and a M.S. in Geology from the University of Alaska-Fairbanks. As a student I was fortunate enough to work with excellent mentors at both universities including Doctor’s Peter Isaacson, Bill McClelland, William Rember, and Michael Whalen. Each of these men was critical to the success of my undergraduate and graduate programs through the breadth of their knowledge, ability to think outside the box, and by employing me to work in their laboratories.
During my bachelor’s degree program I worked in the paleontology lab processing and identifying conodonts, pollen, and spores during the weekdays and in the mineral separation lab processing zircons weeknights and weekends. I was also very involved in the AAPG student chapter as Vice President and President. That volunteer role helped me land a summer field season in the Richardson Mountains of the Northwest Territories, Canada working with Dr. Mike Pope. Undoubtedly the greatest field experience in my early education as a geologist.
During my master’s degree program I studied Lisburne Group carbonates under Dr. Michael Whalen at UAF while working as an intern for Jim Clough at the Alaska Division of Geological and Geophysical Surveys. Two summers working on my thesis in the Brooks Range was a wonderful field experience in a beautiful setting. At ADGGS I focused on coal resources in Alaska including the Fort Yukon Coalbed Methane project. It was a great internship working with fun, driven, and intelligent people. Towards the end of my M.S. Degree I was working two jobs and finishing up my thesis. Mornings I would work at ADGGS and afternoons and weekends in the Kinross-Fort Knox Gold Mine open pit and core facility.
I procured an internship with Kinder Morgan in Midland, TX in 2006, was hired in 2007, and left the company in 2014. I worked on the Yates Field Unit with a great group of folks. I started out as a Geologist 1 and within seven years had advanced to Senior Geologist in Houston, TX.
Working this immiscible CO2 gravity drainage flood was fantastic! Under the direction of geologist Dr. Fred Behnken I logged over 80 slabbed cores in the San Andres, Queen, Grayburg, and Seven Rivers formations and described more than 1000 thin sections. Utilizing wireline logs and core data I placed the facies and sequence stratigraphic framework into Petra and modelled the field using RMS-ROXAR. This would prove to be fruitful as I discovered bypassed pay in pinch-outs and small structural domes in the field.
After many years working Yates I had the opportunity to work Katz Field which is a mixed carbonate-siliciclastic reservoir under CO2 flood. Excellent ichnofacies in the core led colleagues at BEG, KU, and I to update the depositional environment from simply fluvial-deltaic to a bayhead delta restricted embayment system with a longshore drift barrier dissected by carbonate flood tidal deltas.
Following my years with Kinder Morgan I landed a consulting gig with Windy Cove Energy working on potential acquisitions. Working at WCE was incredibly valuable to my personal CO2 EOR education as I learned a completely different aspect of the business.
Currently, I consult through XPSGUSA with my colleague Terngu Utim (http://www.xpsgusa.com). I am also fortunate enough to be the 2017 co-chair for the Southwest Section AAPG meeting with my good friends, David Thomas (Trey Resources), Valentina Vallega (Schlumberger), and recent geology graduate Sofia Caylor (Sulross). The southwest section meeting will be held in Midland, TX May 1st-5th.
Anyone interested can find me on LinkedIN https://www.linkedin.com/in/jessegarnettwhite
Michael A. Raines:
My name is Michael A. Raines. My background is largely in carbonate conventional reservoirs, and mostly in Enhanced Oil Recovery. I started my geologic career in the middle of undergraduate work at West Texas State University (now known as West Texas A&M University), in Canyon, Texas. I had to have a few extra science classes, and stumbled upon a Geoscience Survey class taught by Dr. Robert Savell. He covered a little meteorology, geography, oceanography, and geology.
I loved that class, and the rest, as they say, is history! I changed majors and finished my Bachelor's degree in 1992. From there, I went on to work on a Master's of Science at the University of Oklahoma, in Norman, Oklahoma, working under Dr. Tom Dewers. My research topic was primarily aimed at studying the kinetics of gypsum dissolution. After most of my research and lab work, but very little of my thesis writing, was done, I accepted an internship with Texaco Exploration and Production, Inc., (Texaco) in Midland, Texas during the summer of 1995. There I met many wonderful folks, and discovered how Asset Teams function. At the end of the summer, Texaco Midland offered me an entry level geology position, contingent upon the completion of my MS degree. I was suddenly much more motivated, and finished my thesis writing and defense. I started with Texaco by late October of 1995. I worked for Texaco until Halloween of 2000, when I switched to Kinder Morgan CO2 Co., Inc. (KM), also in Midland, in the same building, and with some of my former Team Mates from Texaco.
That is where I met Jesse and briefly worked with him directly prior to changing jobs. In 2006, I went to work for PetroSource Energy, Co. (PSEC, which is now part of Trinity CO2 Co.) with another group of my former Texaco Team mates, until the oil bust of 2008 / 2009. Then, in 2009, just a couple of weeks after being laid off, I was lucky enough to get on with some of my same former Texaco and some of my old KM Team mates at Whiting Petroleum Corp. (Whiting), which is where I am employed today.
I am currently primarily focused on becoming familiar with my new project, which is shared with two geology co-workers, Andrew Parker, and Dr. Robert Nail. However, I am also an active volunteer in local, regional, and recently international societies. I have served as president of both the West Texas Geological Society (WTGS) and Permian Basin Section SEPM. This summer I will become President of Southwest Section of AAPG. I am also chairman of the WTGS contingent to the AAPG House of Delegates. A few months ago I took over editorship of the Division of Professional Affairs Newsletter, The Correlator.
How did you get interested in CO2 floods?
Jesse Garnett White:
In 2006, I learned through the AAPG Career Center that Kinder Morgan was searching for a summer geology intern. I interviewed over the phone with Mike Raines, was hired for the summer, and worked on SACROC with geologists Cindy Bowden and Dr. Fred Behnken. Working the northern platform of SACROC utilizing production data, pattern flood alignment, water curtain placement, and depositional modeling I helped optimize the pattern areas. My interest peaked when I realized the technical abilities of the folks I was surrounded by far exceeded my own. The Midland engineers and geologists working the CO2 projects were top notch folks and I couldn’t wait to learn more from them. It was a great internship that landed me a full time job with the company.
Michael A. Raines:
When I started with Texaco, I was assigned to the North Hobbs Asset Team, whose purview included the prolific Vacuum Field on the Northwest Shelf of the Permian Basin, in Lea County, New Mexico. A few months after I started, my mentor, Roger Cole, took an assignment with Texaco Houston and transferred out to work on interests in China. Until other arrangements could be made, I worked on the properties (which included 13 stacked pay horizons) in Vacuum Field. This included a newly started miscible CO2 flood in the (mostly) dolomite Grayburg and San Andres Formations, called Central Vacuum Unit. A few months later, we did hire another geologist, Robert Martin, to take over part of the field, but the properties I stayed with included the CO2 project.
That experience started me on my CO2 kick, where I have (mostly) stayed since, working SACROC Unit (Cisco and Canyon limestones) on the east side of the Horseshoe Atoll at KM, the Wellman Unit (Permian and Cisco limestones) on the west side of the Horseshoe Atoll at PSEC, the Postle Unit (Morrow Sands) in the Oklahoma Panhandle with Whiting, and now I have recently been assigned to the mixed carbonate / siliciclastic North Ward-Estes CO2 flood (Yates and Queen Formations, mostly sands) on the Central Basin Platform in Texas, also with Whiting. Prior to KM securing the employment of Dr. Fred Behnken, I also very briefly worked on the famous Yates Field, which will have its 90th anniversary this year, with October 28, 1926 marking the gusher of the Transcontinental Mid-Kansas # 1-A. Happy Anniversary!
What I love most about CO2 floods is the ability to go into old, dying assets and turn them around. I like to see old fields that were in danger of abandonment become profitable again, to provide long-term production for the economy, and (in honor of my depression-era grandfather) to squeeze more oil of that same tube, the way he used to milk toothpaste from a real tube. "Waste not, Want not," as he used to say.
How are CO2 floods different today than 10-15 years ago? What are the main benefits?
Jesse Garnett White and Michael A. Raines:
We have come a long way since the early days of CO2 flooding. We now have some new and interesting improvements in our “Monitoring Tool Box”, along with some potential for further technological development. Many of the learnings from a reservoir operations standpoint were really solidified in the last 15 years. This is especially true for tertiary oilfields under miscible flood, such as SACROC (Miscible: fluid phases that mix together without forming a distinct boundary).
The key issues related to operational improvements can be summarized in terms of Recovery Efficiency (RE), and that is also where our monitoring tools have improved.
The first aspect of controlling RE in miscible flooding is pressure control. We now attempt to insure that CO2 remains in a miscible condition in the reservoir. When pressures drop too low, the miscible bank (oil, water, and liquid CO2) starts to lose cohesion and individual components separate from the bulk mix. This allows each one to respond to reservoir conditions based on its own relative permeability to the whole system. Also, as pressure further drops towards the critical point, CO2 enters vapor phase (Figure 1).
Figure 1: Comprehensive Two-dimensional Supercritical Fluid and Gas Chromatography (SFCxGC). Andre Venter, 2003. University of Pretoria.
In a CO2 flood subsurface environment, reservoir gases travel much faster than liquids, and are the first phase to develop preferential pathways. Once that full pathway between injection and production well has been established, relative perm contrasts causes a single favored pathway for CO2, like rain drops coalescing down a single path on a windshield. So, the flooding operation receives a one-two punch with CO2 “breakthrough.”
A) The oil phase of the flood front is left behind to dissipate as the formerly-miscible fluid breaks into its components. This leaves each fluid type to travel alone, stagnate, or separate with no direct support from a “pushing fluid” coming along behind.
B) The CO2 that does come along later not only ignores the remnants of the miscible bank, but also bypasses all other unswept areas in preference for its new short cut to the producing wellbore. That means the available oil along the pathway is quickly removed. More and more CO2 carries less and less oil as the CO2 gas strips the rock clean of hydrocarbons. This results in failure of the operation to meet the expectations of the reservoir team and management.
Now, modern operations handle the pressure control issue on two levels. On the “Project” (or “Phase” or “Pattern Group”) level, operators typically surround the area with water injectors. This ring of injectors is referred to as a “water curtain”. The purpose of the water curtain is to physically prevent the migration of CO2 out of the patterns, to generate a pressure front that establishes a “no-flow” boundary around the project area, and to maintain pressures at MMP, or at least critical point pressure, in the reservoir. On the “local” or “pattern” level, operators attempt to keep bottom hole pressures on producers (not just the injectors) at or very near the same limits by
A) starting projects later, after reservoir fill-up (with water) has established an adequate reservoir pressure,
B) reducing pump rates,
C) increasing static fluid levels, or
D) completely avoiding artificial lift by converting producers to flow.
The second aspect of RE is to control the vertical distribution of CO2 in the injectors. Ensuring that all zones of interest are receiving adequate amounts of CO2 sounds easy on paper, but in actual reservoir conditions there are many complications in layered systems. These complications favor flow into one interval over some other interval(s). Most of these complications are related to the geologic aspects of the depositional history of the reservoir itself. But some are related to mechanical issues in wellbores. Proper interpretation of flow units is important because of impacts on completion strategies between injector and producer pairs. Proper isolation of zones behind casing is also critical to controlling formation access.
These days, geologists and engineers have quite a few tools to use in monitoring fluid distribution. The most common items are wireline-conveyed logging tools. Production and Injection logs focus on providing information on where CO2 is leaving the injector or entering the producer. These logs rely on a variety of measurements as single data streams, or in combination with other readings, including temperature probes, spinner surveys, chemical or radioactive tracers, and/or electrical measurements. These data streams are used to infer how fluids move into or out of the borehole. We can also use repeat surveys of Neutron-Porosity (NPhi) logs to detect which zone(s) are no longer full of water or oil, because the “gas effect” that is commonly discussed in oil and gas reservoirs, which is caused by methane, also applies to (liquid) CO2. That is, CO2 reduces calculated NPHi, so zones with CO2 added to them appear to loose NPhi with time. The limit with these wireline-based tools is that they only see near the wellbore.
Other ways to see a bit further away (but with less vertical resolution) include 4D surveys (surveys repeated over time) from Cross-Well Seismic (XS), various versions of standard or reverse Vertical Seismic Profiles (VSPs), or Cross-well Electromagnetic Surveys (XEM). In a manner similar to the neutron wireline example, we are looking for changes caused by a switching of fluids in the pore space. CO2 impacts the physical parameters in the reservoir by reducing seismic travel times, or increasing the resistivity of a layer, and those changes are frequently large enough to be detected with tools now available. Of course, the limiting factor on XS and XEM are that they basically create a 2D view, directly between survey boreholes. XS, however, does have the capability for high vertical resolution, on the order of 5 feet per “pixel.” VSPs and XEM both have a little more coarse vertical view, but also have a range of possible configurations, depending on what works best in your reservoir, and with your wells, so some optimization is available. XEM also has limitations based on casing (it needs open hole or fiberglass cased wells to get the best signal).
The final RE consideration is the lateral distribution of the flood front. CO2 from an injector initially enters the reservoir and spreads out as a radial front. However, heterogeneities in the reservoir and physical limits (i.e. flow boundaries imposed by the pressure distribution between wells) impact the shape of the expanding front. Eventually the edges taper, thinning in a “tear-drop” fashion towards the producers. The primary tool we currently have for monitoring fluid interactions far from wellbores is 4D surface seismic. Repeated surveys are shot over time to generate a picture of where changes do (or do not) occur. Direct shear wave (S-wave) data (called 9-Compenent because it includes S-wave vibrators in two directions, compressional wave (P-wave) standard vibrators, and 3-Component geophones with one P-wave sensor and two S-wave sensors) seems to give reliable images of changes related to either the pressure or fluid variation caused by the migrating CO2 flood front.
Some operators have indicated positive results using only advanced processing techniques on P-wave data.
Other operators have reported some success when experimenting with Converted Wave data. (Converted Wave surveys use the 3-Component geophones to detect P and S wave data, but only use standard vibe trucks. A portion of the compressional energy is converted to shear energy when it hits reflectors. This shear wave energy is what is recorded on the S-wave components of the geophones.)
Like standard surface seismic data, the vertical resolution of 4D data is noticeably lower than logs, cross-well, or VSP data, and varies from field to field due to a plethora of surface and subsurface conditions.
Electrical Imaging of reservoirs holds some promise in the near future
. Large surface surveys of induced current may be appropriate monitoring tools in certain settings. The largest hurdle for this technology currently seems to be parsing its depth of investigation into vertical components. Similarly, geophysicists and meteorologists are currently investigating Natural Source Electromagnetics (NSEM) as a potential monitoring tool and geologic imaging tool (Personal Communication, L.J. Berent, 2016). The promise of this technology is that it does have some vertical context. However, it is in its infancy so procedures and specific applications are still under investigation. One limiting factor is that NSEM only provides information on reservoirs deeper than about 5000’, and the lateral resolution seems to be a little coarse (though it may be possible to refine that resolution as better processing techniques are developed).
Another new technology that is being investigated as a potential monitoring tool is the Krauklis Wave (K-wave). The K-wave is a very slow, seismic-related wave that is transported via tube-waves down a borehole to a formation, then across the formation to any hydraulically-connected well. Once the K-wave hits the adjacent well it generates another tube-wave that can be detected at the surface of the wellbore. The speed of the wave is related to the fluid types it encounters along the way so changes to the speed of the wave can be related to changes in fluid types between the wells (SWS-AAPG Annual Meeting, Cannon, 2016).
What are the costs? How have they changed?
Michael A. Raines and Jesse Garnett White:
The cost question is a bit tricky, since a lot of those contracts are proprietary. The cost of running a CO2 flood is not trivial. As discussed above, there are many considerations that go into surface facilities and well work. CO2 operations are quite capital intense, especially in the early years. The exact costs vary greatly based on distance to pipelines, volumes scheduled for delivery (which impacts pipeline sizes), volumes anticipated for recycle (which impacts plant size), plant location, plant type (Ryan-Holmes and Membrane systems are currently most common), existing electrical infrastructure, cost of power, and age of the field (as it relates to the needs of repairing or replacing wellbores). Then there is the cost of the CO2 itself. CO2 supply contracts are very closely held corporate secrets so public data is hard to come by but is one of the top costs of standard (non-start-up) operations along electrical costs.
The main things that have changed in recent times are the way CO2 contracts (from natural supplies) are structured. Older contracts (pre-2000) were typically set at a flat rate per MCF. Newer contracts are typically indexed to the price of oil, but with a floor price that protects the supplier in case of oil price drops. The protection for the operator is a provision in the contract which allows them to reduce purchases to a lower amount called a “Take-or-Pay” volume.
How can operators assure themselves of a CO2 supply?
Jesse Garnett White:
Access to a naturally occurring subsurface CO2 resource that provides an economic long term supply is optimum. Known economically viable subsurface supplies are already being extracted by CO2 companies. CO2 EOR companies without direct access to these naturally occurring supplies purchase directly from the source field operator. Another and currently less economical avenue for most companies is anthropogenic CO2. Anthropogenic resources of CO2 produced from natural gas processing, fertilizer, ethanol, and hydrogen plants where naturally occurring reservoirs are unavailable are starting to look more promising as technology advances. Source to sink distance and access to pipelines can make anthropogenic sources unattractive. That said these sources will eventually be utilized not only for EOR but also CCS (Carbon Capture and Sequestration). ExxonMobil Corporation has been selling CO2 from its gas processing facility in LaBarge, WY to CO2 EOR projects in the region for many years.
What is the role of a geologist in a CO2 flood?
Jesse Garnett White:
First and foremost is to grasp the geology of the field in question, locate flow units for optimal sweep efficiency, and produce hydrocarbons. Of primary importance is how to optimize sweep from injector to producer without losing CO2 and hydrocarbon to the reservoir. Often fractures, faults, misinterpreted facies tracts, or improper perforation placement is to blame.
Of great importance is the ability to converse technically with petrophysicists, geophysicists, and reservoir, petroleum engineers and drilling engineers working the field. A well planned, technically advanced, and efficient operation is highly desirable. Teamwork and fluid technical communication is paramount to a successful operation.
Michael A. Raines:
I would like to reinforce Jesse's comments. Teamwork and interdisciplinary communication are absolutely high priority. You must be able to work seamlessly with your engineering counterparts (on both the production and reservoir side) and technicians; you should learn to work very well with your regulatory group and well with the remainder of your team. You never know when someone looking at a different aspect of the project can make a step change in profitability or find some key insight or data missing from your current knowledge.
What does a geologist need to know to be able to start getting involved in CO2 floods?
Jesse Garnett White:
A complete and careful understanding of subsurface mapping is clearly advantageous. Hence, the basics of geology are necessary to get started in any subsurface project. A thorough knowledge of structural geology, sequence stratigraphy, sedimentology, carbonate and siliciclastic depositional environments, lithofacies, biostratigraphy, and diagenesis is critical to a projects geological success. It doesn’t hurt to have a well-rounded education in development and operations geology, core logging and evaluation, mud logs, wireline and image logs, cross-well, 2D and 3D Seismic, and drilling, petroleum, and reservoir engineering. Other important aspects to consider in a CO2 flood include miscibility gradient, temperature and pressure gradients, subsurface water chemistry, wettability, and well-spacing.
Michael A. Raines:
Again I want to echo Jesse's thoughts and emphasize that when you work with CO2 floods, the communication among wells is the key to success or failure of the pattern. As my long-term engineering friend and co-worker, Robert “Bob” Boomer likes to say… “CO2 Flooding is a Contact Sport.” That means that the CO2 must come in contact with the oil, and also must make it back to a producer. Therefore, you have to be able to think in terms of Flow Units, even more than stratigraphic units (in the event that vertical communication via fractures, perm contrasts, depositional pinchouts, or erosional contacts might override what you would normally expect in a layered flow system).
What are your plans for the future?
Jesse Garnett White:
I am optimistic and the future is bright! I look forward to working on projects both big and small in my career. I hope to continue volunteering in varying roles for AAPG as my career advances. I would eventually like to reach the national and international stage as a proud member and positive role model for the organization and my fellow geoscientists.
Michael A. Raines:
As mentioned earlier, I will be spending some time in the coming year as President of SWS-AAPG, and working on the DPA Correlator. I have two daughters who are freshmen. My youngest is in high school and my oldest is working on a geology degree in college. I plan to optimize time with them before they are both completely out on their own! Other than that, I plan to learn my new project in more detail, trying to optimize our operations at North Ward-Estes. Hopefully this slower time will allow all of us to regroup and investigate all of the personal and scientific issues that we have been delaying due to hectic pace of oil-field life the past few years.
Michael A. Raines – Bio
Michael Raines was born in Pampa, Texas and attended college at West Texas State University in Canyon, Texas. There, he earned a BS in Geology in 1992 before moving on to the University of Oklahoma in Norman, Oklahoma, where he received an MS in Geology in 1995. Mike has spent his entire career, so far, working out of Midland Texas. He started with Texaco Exploration and Production, Inc. in 1995. In 2000, he moved to Kinder Morgan CO2 Company, where he stayed until 2006. Next, Mr. Raines joined PetroSource Energy, Inc. (which became a wholly owned subsidiary of Riata Energy, then SandRidge Tertiary, and which is now part of Trinity CO2 Investments, LLC). Finally, in 2009, Mike joined Whiting Petroleum Corporation, where he is today.
Jesse Garnett White - Bio
AA Spokane Falls Community College
BS Geology University of Idaho (Pollen and Spore Analysis of Miocene Lake Clarkia Site)
MS Geology University of Alaska - Fairbanks (Carbonate Facies and Sequence Stratigraphy of the Carboniferous Lisburne Group, Upper Nanushuk River Region, Central Brooks Range, Alaska)
Energy Section Intern Alaska Division of Geological and Geophysical Survey Fairbanks, Alaska (2004-2006)
Geotemps Geologist Fort Knox Gold Mine Fairbanks, Alaska (2005-2006)
Kinder Morgan CO2 Geologist Midland and Houston, Texas (2006-2014)
Windy Cove Energy Geologist Houston, Texas (20014-2015)
XPSG-USA Consulting Geologist (2015-present)
I am grateful to the following people: Jay Healy at Spokane Falls Community College, Peter Isaacson and William C. Rember (University of Idaho), Bill McClelland (University of Iowa), Michael Whalen and John Eichelberger (University of Alaska - Fairbanks), Jim Clough (ADGGS), Tyler Allen (Terracon - Boise), Michael Raines (Whiting Petroleum), Fred H. Behnken (FHB Stratigraphic Services), Cindy Bowden (WTGS), Fred Garver, Brian Brister, Ron McWhorter, Douglas Lorenz, Pamela Boring, Kiomars Eskandari, and Shelia Echols (Kinder Morgan CO2), Chuck Fox, John Dobitz, Mark Peavy, Andy Casazza, Andy Vescey, and the rest of the crew (Windy Cove Energy), Terngu Utim (XPSGUSA), Derek Allison (Occidental Petroleum), Curtis Helms Jr. (PPDC - Midland), Susan Nash (AAPG), and all of my colleagues associated with the WTGS (especially David Entzminger, Paul Pause, Dexter Harmon, Denise Cox, Paula Mitchel-Sanchez, Jim Adams (deceased), Dave Thomas (Trey Resources), Valentina Vallega and Olfa Zenned (Schlumberger), Sofia Caylor (recent graduate BS Geology Sulross), Herb Wacker, and others (you know who you are), Mehdi Hassani (RMS-Roxar), Jezy Cooke (Apache Corporation), Michael Pope (Texas A&M), Theresa Kemp (Atlantic Resources), Steve Bachtel (and his lovely wife Christine), and all the folks at the BEG-RCRL (especially Charles Kerans, Chris Zahm, and Xavier Janson). I would also like to give a special shout out to Jerome Bellian and David Allen Katz for being real.