A normalized time has been developed that linearizes the rate decline vs. normalized time for a gas reservoir producing against constant well bore pressure during (external) boundary-dominated flow. This allows type-curve matching of the exponential decline curve for a reservoir with any shape. Values of G, kl/l, and k~/rf> can be determined from this type-curve match. It was determined that gas reservoir depletion plotted vs. actual time does not match exponential, harmonic, or hyperbolic decline curves, and future performance can lead to overestimates of reserves and future rate.

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The presence of cavities connected by fracture networks at multiple levels make the simulation of fluid flow in naturally fractured carbonate karst reservoirs a challenging problem. The challenge arises in properly treating the Darcy and non-Darcy flow in the different areas of fractured medium. In this paper, we present a single-phase transient flow model which is based on the Stokes-Brinkman equation and a generalized material balance equation. The generalized material balance equation proves to be exact in both cavities and porous media, and the Stokes-Brinkman equation mathematically combines Darcy and Stokes flow, thus allowing a seamless transition between the cavities and porous media with only minor amounts of perturbation introduced into the solutions. Finite differences are implemented for the solution of the proposed transient flow model. This solution method provides a smooth transition from standard multiple-porosity/permeability reservoir simulators and moreover, it is physically more straightforward, mathematically easier to derive and implement, and more apt to generalization from two-dimensional to three-dimensional cases than alternative techniques. Application of the derived transient flow model is shown by examples of three fine-scale 2-D geological models. The first two models, although simple, provide verification of the proposed transient flow model. The third example presents a more complex and realistic geological model derived from multiple-point statistics simulation technique with the second model used as the training image. The results of the third model form the foundation for future study of multi-phase and 3-D reservoir cases. cavities and fractures (Tuncay et al. 1998) and Darcy flow in the porous media makes the coupled solution of fluid transport in these reservoirs very difficult. Various continuum approaches have been developed for the modeling of fluid flow in naturally fractured carbonate karst reservoirs. Methods based on the multiple-continuum concept model fractures and vugs as porous media with high permeability values (

This paper addresses an advanced oxidation and precipitation water treatment process employed as an on-the-fly fluid pretreatment during hydraulic fracturing operations. The water treatment technology will allow for substantial reuse of flowback and produced fluid while at the same time completely replacing liquid biocide and scale inhibitor fluid treatment during fracs. Additionally, the treatment process generates zero waste. To date, the technology has been used on hundreds of wells successfully treating over 17 million barrels. The paper will report on more than 2 years of field operations on hundreds of frac stimulations as well as numerous pilot operations in multiple shale plays. Dynamic tube-blocking tests show that the treated fluid will not deposit scale even after days of storage in an open frac tank. Field sample testing shows the injected brine has 3 to 6 log-cycle kill of sulfate-reducing and acid-producing bacteria populations. With the move toward environmentally safe chemicals, an economical process eliminating chemicals is a step forward for our industry. The equipment is purposely designed to segue directly into the fracturing process without interfering with service company pumping operations or having any compatibility problems with any service company products. Our paper will show definitive results from field operations of an economic water treatment system that will allow for a reduction in liquid chemical usage and closed-loop management of wastewater. The newest design would treat 80 barrels per minute, occupying a footprint roughly the size of a frac tank. The units can be deployed in tandem for higher flow rate requirements.

The Maureen field, a light oil reservoir in the North Sea which has achieved waterflood oil recovery close to 53 percent of the OOIP is nearing the end of its producing life under waterflooding operations. This field was evaluated as to the feasibility of improved oil recovery through high pressure air injection as an inexpensive substitute for other unavailable or costly gases. Six accelerating rate calorimeter (ARC) tests and five combustion tube tests were conducted to determine the oxidation characteristics of Maureen crude oil while injecting air in the presence of reservoir rock and brine. These tests showed that Maureen oil will reliably autoignite, generate flue gas (85 % N2 and 15 % CO2) and propagate a stable combustion front. In addition with air enrichment, a first contact miscible displacement process can be maintained. High pressure air injection was then modeled as a miscible process using the history matched Maureen waterflood model: the results showed incremental oil recovery due to air injection would range from 17.8 to 26.3 MM STB (4.5 to 6.6% OOIP) depending on the relative location of the air injection wells (flank or crestal). Introduction The Maureen field in the UK sector of the North Sea has achieved water flood oil recovery close to 53 % of the original oil-in-place (OOIP), but is nearing the end of its productive life under water- flooding operations. The water flood has achieved a volumetric sweep efficiency in the range of 90 percent and most of the reservoir hydrocarbon pore volume has been reduced to the residual oil saturation to water of 23 percent, but if abandoned in its present state, Maureen will leave 175 MM STB in place as unrecoverable oil. The next phase of economic oil recovery will require a displacement fluid that is near first-contact miscible, can be recycled, and is available offshore for less than $1.5 US/reservoir bbl. One way to achieve these objectives is through high pressure air injection. High pressure air injection can reduce the residual oil saturation through formation of a miscible gas bank which will displace the remaining oil to the producing wells. This was confirmed by phase behavior modeling of Maureen oil and combustion product gases. Scoping model runs show that high pressure enriched air injection (30 percent oxygen) in a waterflooded reservoir can generate a first-contact miscible fluid in-situ for less than $1.5 US/reservoir bbl. Laboratory combustion tube tests with Maureen oil and core material show that oxygen will oxidize about 3 to 5 saturation units of the oil to create carbon dioxide, generate heat for the steam, and upgrade the oil by 2 to 4 API units. The miscible gas mixture is expected to consist of 34% steam, 16% CO2 and 50% N2. As the extracted oil and steam cool, the foamy oil and water will form a temporary emulsion until carbon dioxide separates from the liquid phases. This temporary emulsion prevents oxygen bypassing the oxidation front and improves sweep efficiency by decreasing the mobility ratio to less than 0.5. Based on Permian Basin experience of enhanced oil recovery from waterflooded reservoirs in west Texas, a carbon dioxide rich gas mixture would be the ideal fluid for increasing oil recovery from the Maureen reservoir. A carbon dioxide gas mixture will recover an additional 8 to 15 percent of the original oil-in-place in the contacted reservoir volume over that achievable by water-flooding. As the reservoir temperature increases due to depth of burial or due to combustion, less carbon dioxide is required in the gas mixture to effectively extract most of the medium to light gravity oil. For temperatures over 200 C, water (in the steam phase) and carbon dioxide can be injected to create a first-contact miscible gas mixture. Experience learned from Amoco's West Hackberry project and Koch's Medicine Pole Hills project shows that it requires about two-thirds of a pore volume of injected air to sweep the reservoir. Laboratory tests show the Maureen oil will autoignite at reservoir temperature, therefore only a single well huff-and-puff test will be required to prove the Maureen oil will oxidize at field conditions. P. 655^