TECHNOLOGY AT WORK

Shared experiences from extra-recovery projects

E. Lance Cole, National Project Manager, Petroleum Technology Transfer Council (PTTC)

ith higher and stabilized (?) oil and gas prices, producers are exploring project opportunities for improving oil and gas recovery. In a recent conference, producers and technology providers alike shared their experiences. Applications varied from proven, widely accepted technologies, such as gel polymers, to more leading-edge technologies like seismic stimulation.

Those participants looking for opportunities in the reservoirs / fields they manage received broad exposure, sufficient for determining which technologies might be a match for their opportunities. Of significance, the expert speakers themselves learned from the experience, both about processes outside their normal realm of expertise and from penetrating questions from other experts.

Maximizing profitability through rapid field development, East Texas tight gas. Historically, conventional wisdom has led to staged developments of tight-gas discoveries in East Texas. These developments have characteristically used a series approach, where waves of development activity progressively down-spacing the field are separated by periods of monitoring, testing and evaluation. Using this approach, optimum well spacing is not achieved until late in the field life, and performance of later infill wells is often lower.

In East Texas tight gas sands, Anadarko Petroleum Corp. has found that a parallel approach to evaluation and development not only increases the asset’s present value, it can improve recovery as well. These improvements are primarily associated with one thing – developing at the optimum spacing early in the field’s life. As with conventional development, initial well spacing is greater than optimum, but the parallel approach allows further development to occur (with confidence regarding optimal spacing) during the conventional monitoring, testing and evaluation period.

To manage risk, Anadarko combines early data acquisition (cores, logs, samples and daily well performance information) and advanced performance evaluation techniques, to identify optimum field spacing and the development plan. Program success depends on understanding these risks early in the field life. Considering data acquisition and evaluation costs as a field-wide investment rather than justifying on an individual well-by-well basis facilitates getting management approval.

With parallel development, it is critical that ultimate performance of new wells be determined quickly. Since conventional decline curve analysis can typically take years of production history to be applicable, Anadarko employs new, type-curve matching techniques to provide early estimates of well performance (contacted gas in place, connected pore volume and drainage area). Applying these methods, together with other advanced reservoir characterization techniques, the operator has demonstrated the ability to proceed rapidly to full field development on optimum spacing.

Optimal well siting in basin-centered gas reservoirs. Such reservoirs are different than normal structural or stratigraphic traps. Gas is widely distributed throughout the section, and exploration requires finding the "sweet spots." Best production is not as closely related to closure or sand thickness. Fortunately, where gas replaces water, there are slow acoustic velocity anomalies, regardless of whether pressures are abnormally high or low. Identification of anomalous velocity zones has proven predictive for identifying "sweet spots." Building on prior R&D and field results, Innovative Discovery Technologies LLC (IDT), a subsidiary of GTI (formerly GRI), has been successfully using this approach.

Data was presented for Muddy production from Riverton Dome in Wyoming. There, the field had normal-pressure production from the crest of the anticline. A regional seal crossed reservoir facies on the flank of the structure. Facies maps are available. Wells located in reservoir facies and having anomalous velocity profiles are commercial, whereas wells drilled on structure have not been economic. In another example, a comparison between predrill and postdrill estimates of ultimate reserves (in the range of 2 – 10 Bcf), considering 20 wells sited using the exploration technique, is quite positive. The last Tcf of reserves in this field was developed with 20% fewer wells due to using this approach.

Independent takes over Wyoming CO₂ flood and increases value. Merit Energy Co. purchased the Lost Soldier and Wertz CO₂ flood operations in Wyoming from BP Amoco in December 1999. In those fields, BP had been CO₂ flooding since 1986. The Tensleep and Darwin-Madison reservoirs, the primary formations, are separately flooded. Since assuming operations, Merit has: 1) reactivated / recompleted 80 wells; 2) increased CO₂ purchases for injection to 40 MMcfd from 22.5 MMcfd; 3) changed WAG cycles and patterns; and 4) upgraded facilities to handle additional production. Production has increased over 1,000 bopd, with an increase in ultimate reserves of 5.5 MMbbl.

When analyzing data, Merit recognized that upside potential existed in Lost Soldier. On a percent of oil-in-place basis, tertiary recovery in the Darwin-Madison was only one-third of that experienced in the Tensleep, and peak response was not as prominent as that experienced in the Tensleep. Although there were other factors, further study revealed that lower recovery in the Darwin-Madison could be attributed to insufficient CO₂ injection. Using existing data, sound engineering and new water-oil ratio forecasting techniques, but without simulation using a sophisticated geological model, Merit estimated the upside potential, developed a production / economic forecast, and began aggressive development. Experience to date has confirmed the production forecast’s reliability.

Immiscible nitrogen displacement, southern Oklahoma. The Quintin Little Co., Inc. operates Southwest Homer Goodwin Sand Units I and II in Carter County in the Ardmore basin, south-central Oklahoma. The Upper and Lower Goodwin sands – at depths ranging from 2,200 to 4,700 ft – were originally produced by a combination of fluid expansion, solution gas and gravity drainage. Developed in the 1950s and 1960s on 10-acre spacing, most wells were completed in the Upper and Lower sands and were fracture stimulated. Porosity is in the 17 – 23% range, and permeability exhibits wide variation in this very laminated, shaly siltstone. Dip ranges from 15 to 29%.

When unitized in the 1980s, reservoir pressure in both units had declined to less than 150 psi from 750 psi. Although larger in Unit I, both Units had a secondary gas cap at unitization. Quintin considered waterflooding, but offset waterfloods only averaged 0.22 secondary / primary recovery ratio, and updip water injection prematurely watered-out wells. The operator also recognized that the secondary gas cap had to be repressurized to prevent resaturation with oil. Both natural gas and carbon dioxide injection were considered, but economic and operational factors led to use of immiscible (updip) nitrogen injection combined with downdip water injection.

Injection began in Unit I in the mid-1980s, followed by injection in Unit II in the early 1990s. The process has been effective and economical. Secondary / primary ratios above 0.6 are more than double offset waterfloods, and further economic reserves exist.

With immiscible nitrogen displacement, there are special considerations / problems which must be addressed. Nitrogen breakthrough is inevitable. Temperature or production logs, Thermal Decay Neutron logs, packer or packer / plug tests, and trial and error methods (set RBP and produce) were all used to identify and isolate intervals producing excessive nitrogen. Mechanical methods of isolation included installation of RBPs and casing patchs (long vented packer). Permanent methods of isolation included squeeze cementing the entire perforated interval and recompleting in productive intervals (has not proven a long-term solution) and cementing the entire perforated interval to P&A to prevent crossflow.

A propane refrigeration unit installed in 1999 to strip liquids from the produced nitrogen stream has proven profitable, recovering more than 26,000 bbl of liquids from June 1999 through April 2001. Paraffin problems, which were always a problem, worsened with nitrogen production. Methods most effective for paraffin control include: 1) batch treating with condensate mixed with paraffin chemicals; 2) wellhead magnetic fluid conditioners for reducing flowline chemical / hot oiling costs; and 3) downhole direct chemical injection through stainless steel tubing. Of these, direct downhole injection has been the most effective.

Acknowledgment

Case studies were presented during "Maximizing Recovery 2001," a conference organized by Marcus Evans (www.marcusevanstx.com), June 25 – 26, 2001, Houston, Texas.