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Production decline curves of three represen~ tative low permeability gas wells in the Piceance Basin are analyzed. These wells produce from the Mancos "B", Mesaverde and Wasatch formations, respectively.It was found that long term production in these wells could be approximated using linear flow equations. This observatidn leads to the development of a decline curve method for predicting rate-time behavior based only on one or two years at production data. The method is easy to apply and requires only data which is routinely reported to state oil and gas regulatory agencies. This type of data is public information and is readily available in most states.The observed long-term linear flow behavior indicates that fracture lengths are much longer than would be expected from hydraulic fracturing treatments. possible explanations for this behavior are discussed. The possibility of using short-term test data to define the long-term production decline curve is also discussed.

This paper describes an improved oil-recovery process that uses carbon dioxide in viscous, undersaturated oil reservoirs where the oil zone is underlain by bottom water. The results of a single-well pilot test are presented and an analysis of the potential of the process based on presented and an analysis of the potential of the process based on mathematical model studies is discussed. Introduction Improved oil recovery recently has received much attention. However, the new recovery methods being proposed are generally less widely applicable than proposed are generally less widely applicable than the standard recovery technique of waterflooding. For most reservoirs, the recovery scheme must be "tailor-made" to optimize recovery. This is especially true of the Lower Cretaceous sandstone reservoirs of southeastern Alberta. These consolidated sandstone reservoirs are characterized by (1) high permeabilities (500 to 15,000 md), (2) high porosities (20 to 30 percent), (3) medium oil viscosities (3 to 100 cp), (4) low saturation pressure (50 to 800 psi), (5) low solution gas-oil ratios (30 to 250 scf/STB), and (6) bottom water and varying degrees of natural water influx. The presence of bottom water in conjunction with high-viscosity oil results in relatively low oil recoveries since recovery in these reservoirs is controlled by water coning and is inversely proportional to oil viscosity (Fig. 1). This situation precludes the use of most currently available improved oil-recovery schemes. It has been shown that for a given oil viscosity, recovery under water-coning conditions can be improved by increasing total fluid rate to extend economic limits; however, for viscous oil reservoirs, more dramatic recovery increases should be possible by decreasing oil viscosity to increase oil rate. Applying heat to the reservoir is one of the most widely used methods for reducing viscosity. Steam injection has been successful in reservoirs with associated water zones where the water volume is small relative to the oil volume. An alternative to thermal methods is the reduction of oil viscosity by chemical means. By contacting he undersaturated oil with a suitable gas, viscosity reduction of the same order of magnitude as possible with thermal methods can be achieved. Suitable gases include CO2, methane, ethane, or propane, either as pure components or as mixtures. CO2 Recovery Schemes Most of the current CO2 recovery schemes are contended to be miscible. (A review of miscible CO2 flooding was recently presented by Holm.) Miscible CO2 displacement is preferred to immiscible CO2 displacement because the miscible process can potentially displace 100 percent of the oil in place. However, for undersaturated crude oil reservoirs, the benefits if immiscible flooding can be significant because of high CO2 solubility in the oil. The benefits of oil carbonation have been known for some time. There are seven mechanisms in the CO2 displacement process believed to contribute to improved recovery:oil-viscosity reduction,oil swelling,energy supplied to the reservoir,vaporization of crude oil,blowdown recovery,stimulation effects, andinterfacial-tension effects. With the exception of interfacial-tension effects, these mechanisms all have been discussed extensively in the literature. JPT p. 1248

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A polymer flood was initiated in the Taber South Mannville B Pool in February, 1967. The reservoir, which contains a viscous, highly undersaturated crude oil with no bottom water, was depleted to the bubble-point pressure of 400 psig prior to polymer flooding. A 20 per cent hydrocarbon pore volume slug of polyacrylamide (Pusher* 700) was injected at the center of this long, narrow Lower Cretaceous' sandstone reservoir. In early 1972, injection was converted to plain water by gradually reducing polymer concentration. The reservoir was studied with reservoir simulation models in an attempt to identify incremental polymer flood oil recovery (relative to waterflood). It was found, because of unknown polymer quality in the reservoir and uncertainties in transmissibilities, that incremental polymer flood oil recovery could not be quantified. Results of a wettability study using restored cores under reservoir conditions are presented. The potential effects of wettability on polymer flood performance are discussed. It is not possible, using existing techniques, to quantify quality of produced polymer solution from the field. Some indirect observations on polymer quality are presented to help shed some light on the performance of this major polymer flood. Introduction THE TABER SOUTH Mannville B Pool, located in southern Alberta, was discovered in 1963, The pool consisted of 23 completed producers drilled on 40-acre spacing when polymer flooding was implemented in early 1967, Polymer was added to the injected water until the middle of 1972, at which time a 20.% HOPV slug of polymer had been injected into the reservoir. The polymer slug is currently being displaced through the reservoir with plain water, which consists of produced water plus sufficient fresh water to replace reservoir voidage. Oil recovery to December 1974 was approximately 18 per cent of the original oil in place. Our objective in this study was to evaluate polymer effectiveness by comparing polymer and waterflood performance using numerical simulation" models. Intercomp's three-phase, compressible polymer model was used to study the Taber South Mannville B Pool performance. The results are presented below. Geology The Taber South Mannville B Pool is an offshore barrier bar sandstone reservoir of Lower Cretaceous age. The reservoir rock, a fine-grained sand containing significant amounts of glauconite and- pyrite, is vertically homogeneous, with only a few minor shale stringers. The areal permeability variation is low, with tighter areas near the edges of the sand body. The pool is approximately 5 miles long and 1/2 mile wide. No initial gas cap or water zone is associated with the reservoir. A maximum net pay of 73 ft occurs in two wells, 3A-16 and 11–16, as shown in Figure 1. The sand reaches a structural high of 97 ft subsea in section 16; the base dips northwest at about 30 feet per mile. The average reservoir depth is 3250 ft. Basic Reservoir Data Six of the 31 completed wells in the pool have been cored. The core analysis indicates a low permeability variation, with the highest measured permeability and porosity being 6656 millidarcics and 33.9 per cent, respectively.