Highlighting Optimization of Mature Assets
by Dwight Rychel and Lance Cole, Petroleum Technology Transfer Council
Excerpts in PTTC Network News, 3rd Quarter 2005

Mature wells—what are we to do with them? They've been there a long time, maybe so long that people look right past them as they look for the next prize. Fortunately for those with patience and ingenuity that are willing to "smartly" work hard, there is still lots of cash in "them thar hills." Hart's recent Brownfields: Optimizing Mature Assets (BOMA) Conference (Sept. 19–20, 2005 in Denver) was all about intelligently working those hills to wrestle more of the buried oil and gas treasure from them. Capturing insights from this conference for this article naturally led PTTC to point people toward information/insights from other sources.

In addressing conference attendees, Bill Pike with Hart E&P noted two key points: (1) oil and natural gas dominate the primary energy production today, and will continue to do so in the foreseeable future, and (2) the oil and gas supplied from new fields will decrease from 50–60 % in 1960 and 15–18 % today to 7–10 % ten years in the future, making it very important to optimize the mature field production. There will be many wells to optimize—at the start of 2004 in the U.S., there were about 393,000 marginal oil wells and 260,000 marginal gas wells, according to a recent study performed by DOE's National Energy Technology Laboratory (SPE 98014). These wells produce 28% of oil production and 11% of gas production. Moving forward to 2025, this contribution will increase to 32% of oil and 17% of gas. The number of marginal oil wells will decline while the number of marginal gas wells will increase significantly, with much of that growth occurring in the Rocky Mountain region.

Industry presentations during the conference had a strong focus on natural gas production and related technologies. There are often several required in combination that will remove/cause less damage or solve operational problems. There is some natural spin-off appropriate for marginal oil wells. Some key insights from different presenters include:

• There must be a proactive, integrated approach to production enhancement. This approach identifies opportunities as opposed to reacting to problems, high grades those opportunities and applies the solution in groups. It is project-based and focuses on cost effective applications proportional to the asset value and projected upside. (Mark Brinsden, Expro Group)

• To augment the resources of local asset teams for dealing with mature fields, Chevron has created two new technology work teams—Formation Productivity and Production Engineering. Further, they will form small teams of production engineering experts to go "on location" to work with the asset teams to analyze and remediate production and injection problems. Expertise within these teams includes, among others: lift optimization, wellbore nodal analysis, screening inactive wells for sand and water cut improvement, and stimulation expertise. (Brian Llewelyn, Chevron Energy Technology Company).
• As he discussed gas well liquid loading issues, George King with BP stressed that mature field optimization must be much more than an "office" exercise, reinforcing the "on location" concept that Chevron employs. The people "on the ground," the field records, and visual inspection/observation all provide essential clues that are relevant.

Water Management
Gas Wells. With maturing gas wells, liquid loading can be a dominant problem. George King with BP noted how critical it is for operators to:

• Analyze well behavior and detect liquid loading,
• Understand water sources and identify the source of the problem,
• Calculate the critical velocity to remove liquids, and
• Among the several technologies available for liquid loading, choose one that matches the problem (i.e., screening criteria). Note that in this realm there may not be one "best" technology—several may work and there is a certain amount of "try it and see" when deliquifying gas wells.

Both King and John Misselbrook (BJ Services) discussed the technology choices available today, along with their advantages and disadvantages. James Lea at Texas Tech University also has recognized expertise. Readers are referred to an article published in SPE's Journal of Petroleum Technology (April 2004, p. 30+), which PTTC summarized in a past newsletter available online at www.pttc.org/newsletter/2qtr2004/v10n2p4.htm. Beyond general insights, Lea's article lists 23 references, many of which are SPE papers presenting field results.

Those wanting to learn more should consider participating in the Annual Gas Well Deliquification Conference organized by the Artificial Lift Research and Development Council (www.alrdc.com) and Texas Tech's Southwest Petroleum Short Course which is held each spring in Denver. Some field results presented in the 2005 Conference are summarized in PTTC's Tech Connections column in the April 2005 issue of The American Oil & Gas Reporter (www.pttc.org/columns/aogrcoapr05.htm). These typify what one can expect by attending the conference.

Through the years PTTC has published several relevant case studies in its Petroleum Technology Digest in World Oil (www.pttc.org/case_studies/case_studies.htm), covering an automated soapstick launcher (Sept. 2002), capillary strings (Feb 2003) and a 2-piece flow-through plunger (Aug 2003). PTTC also devoted the State-of-the-Art article in Network News in spring 2003 (www.pttc.org/newsletter/1qtr2003/v9n1p7.htm) to gas well deliquification issues.

John Misselbrook with BJ Services described one of their new technologies, the AquaLift jet pump. Using concentric installed coiled tubing, it creates three conduits: one for gas production, one for liquid production and one for pump power. The pump is on the surface, so there are no moving parts at the bottom of the well, which increases its reliability. It is a good alternative where the pressure is depleted but has good produceability, particularly intermediate depth gas wells making a moderate amount of water. An example was presented of an 8,000 ft. well producing 200 Mcf and 40 Bbls of water per day through 2 3/8-in. tubing. If the well is choked by 25%, it loads up and dies. The result of installing a velocity string is compared with the AquaLift option. With only 13 hp, the jet pump delivers the 40 Bbl/day of water and dry gas to the surface while the 1 3/4-in. velocity string works but only until a modest reduction in bottomhole pressure occurs.

Oil Wells. Excessive water production is not just a "gas well" problem. Some time ago PTTC devoted resources to capturing "common sense" knowledge about managing water production into a concise handbook available through its website (www.pttc.org/pwm/produced_water.htm). Production chemicals are another of those "every day" operational things that it behooves operators to devote some attention to. BJ Chemical Services spent some time during the conference discussing the current economics of chemical remedial services in tubulars, near wellbore and reservoir and discussed specific treatments for the problems cited.

Polymer-gel treatment for water shut-off was one of the technologies discussed. There is a science to success with water shut-off treatments. Those science insights, delivered by two individuals well respected in the field (Randy Seright of the Petroleum Recovery Research Center at New Mexico Tech and Bob Sydansk, retired Marathon and involved in developing the popular MARCIT^TM technology) in a 2004 PTTC workshop in Houston, have been captured online (www.pttc.org/solutions/sol_2004/536.htm). Water shut-off treatments have been quite successful in the Kansas Arbuckle. KU's Tertiary Oil Recovery Project Group has developed a website where individual well treatment results are accessible (www.kgs.ku.edu/Magellan/Polymer/index.html).

Dwyann Dalrymple, Halliburton, described their new WaterWeb^TM product (www.halliburton.com/newsletter/archive/2004/hesnws_050304a.jsp), one of several relative permeability modifiers (RPMs) available from the service companies. WaterWeb's unique polymer chemistry impedes water at the source, enhancing hydrocarbon flow. It works by adsorbing onto the rock surface, reducing permeability to water seven to ten times more than it does to hydrocarbons. Field experience showed success at reducing produced water ranging from 50% to 80%, the key being to use the screening criteria to determine if the reservoir is a good candidate. Rick Flattern's article on RPMs ("RPMs and the Holy Grail," Offshore Engineer, December 2003 excerpted in PTTC's 4th Qtr 2003 newsletter available online at www.pttc.org/newsletter/4qtr2003/v9n4p5.htm#1) describes RPMs more fully.

Downhole oil-water separation is one option for managing excessive water production. Through the years, industry has developed and tested various techniques to do this. In a 2004 "White Paper" for DOE, John Veil with Argonne National Laboratory summarized industry field experience (59 DOWS trials, 62 DGWS trials) with downhole oil-water separation.

Excerpted in PTTC's newsletter (www.pttc.org/newsletter/4qtr2004/v10n4p3.htm#2), Veil indicates that, as of that point in time, risk and cost considerations had chilled industry's interest. In the Conference, Gordon Graves with Well Completion Technology, Inc. somewhat reinforced the state of current reduced interest in downhole oil/gas/water separation. Statistics were presented on 15 worldwide DOWS applications and 53 DGWS applications in the 1994 to 1998 time frame with commercial success, but no recent applications.

Stimulation
Stimulation, whether for existing or new wells, is on every operator's hot list. Stimulation is one of the most effective means of prolonging and maximizing production from mature wells. In the Oct-Dec time frame alone (see page 2, Meeting Alerts), SPE is conducting three Advanced Technology Workshops related to tight gas completion/ stimulation. One reason operators are paying more attention to stimulation is that recent work shows hydraulic fractures are much more complex than we think and we don't always know where they go. In a DOE-supported project, Pinnacle Technologies, Inc. presents several examples (presentations from day-long workshop online at www.energyconnect.com/pttc/archive/doe_deepgas.htm). With a lot of attention and potential, there are many new products/approaches under development. Three examples discussed during the conference follow.

Propellant Stimulation - Courtesy Mark Brinsden, Expro Group

Propellant Stimulation. In India, Expro Group has been involved in a field test of propellant stimulation. The propellant stimulation combines fuel and oxidizer. The rapid burn releases energy in the form of a hot high pressure gas (CO2), which mixes with the wellbore fluids to form a froth. This froth enters the perforations, breaks down the rock and pushes fractures into the formation. The Neelam Heera field in offshore Mumbai, operated by ONGC, had been experiencing a relatively sharp rise in the water:oil ratio (WOR). After reviewing the production data and potential treatments the propellant stimulation was determined to potentially be the most effective. Mark Brinsden with Expro noted that seven wells were initially identified as candidates. Based on production and stimulation models, the candidate list was pared down further and additional downhole data were obtained. Two wells were treated. In the first the skin was reduced from +7 to +4.5 with a 41 BOPD increase and slightly better water-oil ratio. In the second well, the skin improved from +8 to +7 and oil production increased 244 Barrels/day.

CO2 Preflushing When Acidizing. With acid treatments, John Gidley, Consultant, contends that the precipitate of silica that occurs with an acid job reacts with oil and forms emulsions and sludges that damage the reservoir. To prevent the contact of oil and acid, he recommends a pre-flush of CO2. Licensed to Halliburton, BJ Services, and Schlumberger, CO2 pre-flushing has been applied on 103 wells, primarily Gulf of Mexico sandstones, since becoming commercially available and only two have been considered failures. In his presentation Gidley cited three examples illustrating the dramatic production increases that are achievable. In comparing conventional acid treatments on wells with similar skin, from +165 to +170 to the CO2-acidizing treatment, the conventionally treated wells skin improved to +50 to +112, while the CO2 treated well improved to +5. Oil production improved six-fold versus doubling in the conventionally treated wells. Further results can be seen at www.gidley.com.

With UBD techniques, one strives to stay under-pressured at all times, while with MPD one may not always be under-pressured, but the pressure differential is always managed. The goal in either case is minimizing formation damage. Don Hannegan with Weatherford International, Ltd. showed conference participants the tools and different MPD techniques, discussing when to use them and illustrating the advantages with field examples.

Coiled tubing drilling (CTD) offers potential in selected environments where one must drill lots of wells quickly and efficiently. Common in Canada in selected environments, CTD is gaining traction in the U.S. Rosewood Resources has been using a rig developed by Advanced Drilling Technology, Inc. (Tom Gipson) to drill Niobrara wells in northwest Kansas. (see slides 6–9, presentation at recent DOE/PTTC Microhole Technology Integration meeting available online at www.microtech.thepttc.org/presentations/aug_17_2005_mtg_1/gti_rig_m1.pdf).

These 1,500 ft wells are being drilled in 20 hrs with cost savings versus conventional drilling estimated at 29% and there are far fewer environmental consequences. These results and exploding Canadian growth in CTD provide a compelling argument that CTD will be part of the U.S. solution. The referenced Rosewood/ Advanced Drilling Technology/GTI project is one of 16 co-funded projects within DOE's Microhole Technology Program (www.microtech.thepttc.org/).

Often re-development of reserves in mature fields will involve a variety of technologies. John Slade with Encana illustrated this point during the conference with a case study of the Jen Marie formation in British Columbia. Techniques employed include horizontal drilling, matting for year round access, well surveys using air photos, GPS and side-looking radar imagery, reservoir characterization and infill drilling as well as analyses of producing wells.

Advanced Drilling Technology, Inc.'s rig on location in Kansas - Courtesy GTI

Looking Towards The Future
There are lots of exciting, complicated and expensive technologies emerging in the oilpatch. They might require modification, but they shouldn't be counted out for mature assets. Automation, Smart Wells and the Digital Oil Field are one example. Systems may need to be a bit more elementary for the economics to work in mature assets, but industry is finding there are opportunities in this realm. In his conference presentation, Mike Konopcczynski with Well Dynamics noted how  "smart" operations can optimize production, reduce well intervention and operating costs, and even reduce capital expenses by enabling development with fewer wells. Along with examples from the North Sea and Saudi Arabia, he noted use in a domestic CO2 flood.

One can never know too much about the reservoir. Vertical seismic profile (VSP) surveys are quite useful for better defining them, but they can be costly. DOE firmly believes that the economies to be realized from microhole drilling will economically enable "designer seismic." As Roy Long with DOE described it, designer seismic is the ability to drill a low-cost, small diameter well anywhere the field geometry dictates (hence designer), place small geophones in the well and produce a low cost VSP survey. Los Alamos and Lawrence Berkeley National Laboratories have been working to demonstrate the concept utilizing man-generated and natural seismic events in a field demonstration at the Rocky Mountain Oilfield Testing Center (detailed fact sheet can be found on the Fossil Energy web site www.fe.doe.gov for project number FEW03FE06-04).

Tom Davis, Colorado School of Mines, discussed using 4-D (3-D over time), multi-component seismic with other petrophysical measurements to characterize a reservoir (in this case a tight gas reservoir in the Piceance Basin) to optimize the development. Graphics were presented as well as the resulting drilling plan.