bluuebunny/crossref_metadata_2025_split huggingface dataset:
Implementation of Waterflood in Joffre Viking I Pool
Authors: Coskuner Gokhan , Bamsey Al , Stanton Micheal 
Published: December 2007

Abstract
The Joffre Viking I Pool was discovered in 1994 in central Alberta. Since discovery some fifty wells drilled on 64 ha (160 acre) well spacing have delineated the reservoir covering an area of approximately 38 km2. The pay zone is a marine bar sand with a thickness of up to 1.3 m and a porosity of up to 17%. The permeability of the formation ranges from 1 to 10,000 md) with the average being above 500 md in the better parts of the pool. The reservoir contains a slightly undersaturated 41.5 API oil having an initial discovery pressure of 10,367 kPa. The production mechanism is solution gas drive.
The average pressure of the pool had declined to approximately 5200 kPa by October 1996 accompanied with ever increasing produced gas oil ratios (GOR) as a result of liberated solution gas. The declining productivity and increasing GOR lead Blue Range Resource Corporation (BRRC) to consider implementing a waterflood operation to maintain the pressure in the pool while mobilizing additional oil.
This paper describes the results of a numerical simulation study conducted on the Joffre Viking I pool. The numerical model was used to history match the past behaviour of the field and to predict the future performance for depletion drive and various waterflooding scenarios. It has been found that the ultimate recovery from the field can be increased by more than a factor of two through waterflooding while maintaining the reservoir pressure. Encouraged by the results of the numerical simulation study, a waterflood has been implemented in the field. The initial field response is presented in the paper. A comparison between the predicted response and the actual field response is made and the differences are discussed.
P. 79
A Comparison of Forecast and Actual Production after a Decade of Field Operations in
Authors: Brady C.L. , Lee L.P. , Lee S.K. 
Published: December 2007

Abstract
The Alpha Unit (Table 1) produces from the Minnelusa formation at an average depth around 7600 ft. Alpha, discovered in 1987, was the largest oil discovery in Wyoming for that year. Developed on 40-acre spacing, primary reserves from nine producing wells was expected to yield 1.4 MMBO. Implementation of a three-stage polymer-augmented waterflood, very similar to the programs implemented by Sloat, showed the potential of an additional 4.5 MMBO. Laboratory studies of cores, injection water, and reservoir fluids, gave guidance to formulating the injection program. Mack and Duvall's evaluation of this type of injection strategy at other Minnelusa floods served as a check for expectations at Alpha. This paper documents the data and forecasting techniques used at Alpha and compares forecast production to actual production obtained.
P. 123
Water Shutoff Treatments in Eastern Alberta: Doubling Oil Produciton, Decreasing
Authors: Samari E. , Scott D.L.T. , Dalrymple D. 
Published: December 2007

Abstract
Poor primary cement jobs in the Provost area of eastern Alberta, Canada, have resulted in approximately 200 wells being classified as economically marginal. The inadequate cement bonding in these wells has caused the channeling of water from the formation below (as in Dina "C," Fig. 1). Analysis of the production data supported the thesis that channeling was the principal reason for the increase in water production. In 90% of the cases observed, it was 1 to 6 months before the water cut rose from the initial level of 0 to 10% to as high as 98%; in many cases, this increase occurred immediately after the primary completion of the well. Cement-evaluation logs that were run on a number of candidate wells confirmed that channeling of water was the cause of the sudden increase in water cut.
The producing formation is the Cummings sandstone, which was deposited in the early Cretaceous era. The average porosity in this field is 28%, with a permeability range of 200 to 3,000 md and an API crude gravity of 21.60. Bottomhole pressures and temperatures range from 4,500 kPa to 5,500 kPa, and from 27 C to 30 C, respectively. The depth in the 25 candidates ranges from 750 m to 1000 m, and the average water cut before treatment was 98%.
Previous attempts to control water production by using a silicate-based polymer slurry and Class-G cement had met with limited success. These treatments had logged an average success rate of 40%. An improved treatment design was proposed: a silicate-based polymer slurry followed by an ultrafine cement blend to assist in sealing the channel permanently. If necessary, a Class-G cement blend would follow to ensure the success of the cement squeeze.
The following criteria were used to evaluate the relative success of each treatment:
The equivalent of 4 m3/D of incremental oil production was sustained for a minum of 100 days to achieve a payout for the treatment (=﹩40,000 CDN) at a net selling price of ﹩100 CDN/m3 of oil.
Water cut was decreased by at least 15%.
Savings were accrued as a result of decreased water production. Although this cost is minimal, the impact on treatment plants running at maximum capacity can be quite significant.
The treatments resulted in an incremental increase of 104 m3/D of oil initially and a decrease in water production from 3,927 m3/D to 63 m3/D. The project started in July 1996, and the last of the candidate wells was treated the following December. According to the production numbers of February 1997, the treated wells were producing an incremental 78.8 m3/D of oil, and 674.7 m3/D of water. The overall success rate of these water shut-off treatments rose to 75%, in contrast to the previous 40% success figure.
P. 153
Unconventional Miscible EOR Experience at Prudhoe Bay
Authors: McGuire P.L. , Redman R.S. , Mathews W.L. , Carhart S.R. 
Published: December 2007

Abstract
This paper summarizes the conceptual development, reservoir simulation, and field testing of a new miscible EOR recovery process at Prudhoe Bay. Two distinct variations of this process have been evaluated.
The vertical Miscible Injectant Stimulation Treatment (MIST) process involves completing a production well at the bottom of a thick, continuous, watered-out interval. A large slug of miscible injectant (MI) is injected, followed by a small slug of chase water. The MI sweeps rock not contacted by previous MI injection and drives EOR oil to offset producers. It also creates a mobilized oil bank in the vicinity of the production well. The well is then recompleted at the top of the reservoir and returned to production service.
It is particularly advantageous to utilize this vertical drive process in conjunction with horizontal wellbores. In the lateral MIST process, a horizontal lateral is drilled along the base of the reservoir from either a production or injection well. MI is injected sequentially into several intervals along the lateral to mobilize EOR oil from previously unswept areas. The lateral well is then returned to normal production or injection service.
Simulation data indicate that the vertical MIST process could recover over 200 Mstb of incremental oil per well at initial rates of up to 1000 stb/D. Calculations for the lateral MIST process indicate potential recovery of more than a million barrels of incremental EOR per lateral.
Field results have been mixed, but are encouraging. The vertical well MIST showed litfie response, but it did provide valuable insight into the performance of the MIST process. Incremental EOR from the three MIST lateral wells is over 1.3 MMstb, with current rates of about 4000 stb/D.
P. 249
Effects of Polymer Adsorption and Flow Behavior on Two-Phase Flow in Porous
Authors: Zheng C.G. , Gall B.L. , Gao H.W. , Miller A.E. , Bryant R.S. 
Published: December 2007

Abstract
To determine the effect of water-soluble polyacrylamide polymer adsorption and flow behavior on oil recovery, both steady-state and unsteady-state flow experiments were performed on Berea sandstone and reservoir cores. Berea sandstone core is strongly water-wet while the reservoir core is mildly oil-wet. Relative permeability curves and polymer adsorption measurements were made at residual oil saturation and 100% water saturation for increasing polymer concentrations. Mobility measurements were made at different polymer concentrations and shear rates.
A selective reduction of the relative permeability to water with respect to the relative permeability to oil was observed for both Berea and reservoir sandstone cores. The reduction of the relative permeability to water in the presence of oil phase is more than that at 100% water saturation. As polymer concentration increases, polymer adsorption, irreducible water saturation and relative permeability reduction increase. Residual oil saturation remains almost the same. Wettability is beneficial to water-soluble polymer adsorption. In reservoir core, relative permeability reduction could be attributed to both wettability change and pore-size restriction. Polymer adsorption isotherm follows Langmuir's law. Relative permeability reduction as a function of polymer adsorption exhibits an "S-type" curve. It increases exponentially as polymer adsorption increases and eventually approaches a constant. An empirical model was proposed to correlate this characteristics.
As predicted by the depletion layer and viscoelasticity theories, flow behavior of polymer solution in porous media is found to be significantly different from that in bulk solutions. A modification was made to the existing shear rate model based on mobility measurements, showing that the depletion layer effect is in direct proportion to polymer concentration, and is more significant in the reservoir core than in Berea core.
New models were incorporated in UTCHEM, a chemical flood simulator developed by the University of Texas. These models can provide more accurate prediction of the combined effects of relative permeability reduction and viscosity over existing models. Case studies show that the long-lasting relative permeability reduction by polymer adsorption is likely to maximize the benefits of polymer solution in polymer flooding. Increased understanding through simulation may lead to improved field profile modification and near wellbore treatments. The effects of cross-flow and the degree of relative permeability reduction are two critical factors to determine polymer placement strategies and success.
P. 293
Mechanistic Study of Disproportionate Permeability Reduction
Authors: Nilsson S. , Stavland A. , Jonsbraten H.C. 
Published: December 2007

Abstract
It is a common observation that gels in a porous media reduce the permeability to water more than that of oil. Core floods on sand packs using well defined model media has been carried Out to elucidate the matter.
Three different packing materials have been used, acid cleaned quartz sand, Teflon powder and a mixture of quartz and Teflon. Quartz is strongly water-wet and Teflon is oil- wetting. The use of model media gives a good control of wettability effects. The systems used are:HPAM based polymer with an added crosslinker orbiopolymer.
The brine is synthetic sea water and the oil is a white oil.
The results show that the disproportionate permeability reduction (DPR) effect can be interpreted by a mechanism with segregated pathways for oil and water. In a porous media preferred pathways for oil and water are governed by the wettability and to some extent the pore size. A water based gelant will flow in the water preferred pathways and block these channels. The largest DPR effect is observed in mixed wetting media where the difference between oil preferred and water preferred pathways is enhanced compared to homogeneous wetting media. The oil saturation at which the gelant is placed has also been shown to be of importance. Decreasing the oil saturation at which the gelant is placed gives a stronger permeability reduction towards both phases.
P. 335
Horizontal Wells in the Algyo Field, Hungary-Evaluation of a Successful IOR Project
Authors: Palasthy G. , Pipicz V. , Munkacsi I. , Tromboczky S. 
Published: December 2007

Abstract
Compensation of the decreasing domestic recoverable reserves can be supported by further development of existing, producing fields in addition to successful exploration. Along with the application of different EOR methods, considerable results can be achieved by horizontal wells. With the application of this technology, the hydrocarbons which seemed to be hidden in unreacheable parts of the reservoirs become economically extractable reserves increasing the value of the field.
The first horizontal well in Hungary was drilled in 1989 and thereafter 32 horizontal sections were established. The 70% of these wells are in the Algyo field. In this field, the Alsopannon-l3 reservoir should be stressed, where 12 oil and 3 gas producing wells were kicked off for horizontal sections in the period of 1993/97. The successful results highlighted that this technology can be applied in the case of mature fields on the one hand, and, on the other hand gave momentum to the application of the method in a wider spectrum in this field. The findings and experiences achieved by horizontal wells in the Algyo field are summarized in this paper.
P. 407
Improved Field Recovery by Controlling Gas Production in Hetrogenous Gas Injection
Authors: Hiekal Salah A. , Kamal Mohamed , Mosseir Mohamed 
Published: December 2007

Abstract
The Zeit Bay field reservoir units consist of sandstone and carbonates, partially overlaying a tilted block of fractured basement reservoir with a complex drive mechanism. A secondary recovery scheme of gas re-injection into the original gas cap was initiated to maintain reservoir energy and minimize pressure decline. About 45 development wells are actively depleting the reservoir. The original oil leg was 850 ft TVT, but now the oil leg varies from 50 to 200 ft TVT. With this limited oil leg, different problems arose. The most serious problem was the increase in gas production, that resulted in a decrease in gas injection to gas production ratio (GI/GP). The decrease in the Gl/GP ratio results in a fast field decline rate that reflects negatively on the field sweep efficiency. In addition this decrease will hinder the gas cap expansion, and hence will give chance to premature water breakthrough. These problems were treated and controlled by the following measures:Drilling new infill wells horizontally, with a sufficient stand off from the GOC. The last well drilled horizontally in the Sandstone formation of Zeit Bay field produced about 2500 bopd with a productivity index of about 500 bbl/day/psi.Controlling the gas production from high GOR wells. More than 5 wells were classified as high gas oil ratio wells producing at 7000 scf/bbl or more. The intensive gas production was controlled in these wells using one or more of the following procedures:Shut down policy that includes both field and individual wells.Workover plans which include chemical gas shut off using polymer injection into channels behind the casing or mechanically using straddle Packer and cemented casing liner. Accordingly, these high gas wells have acquired a sharp decrease in their GOR, which helps in saving the reservoir energy.
Currently the 5 wells produce under gas lift assistance with very low GOR, thus saving more than 30 MMSCF/D of the previously produced gas, and increasing the field oil production plateau by about 3000 bopd. In addition, the GI/Gp ratio increased from 60% to 80% resulting in a better sweep efficiency and decreasing the annual field decline from 30% to 14%.
P. 423
Improved Surfactant-Alternating-Gas Foam Process to Control Gravity Override
Authors: Shi J-X. , Rossen W.R. 
Published: December 2007

Gravity override in foam mobility-control processes results from the competition between lateral pressure gradient and gravity. Therefore, overcoming gravity override with continuous foam injection requires raising injection-well pressure, possibly risking fracturing the formation. Foam processes employing surfactant-alternating-gas (SAG) injection at a fixed injection-well pressure, however, can overcome gravity override without excessive injection pressures. This advantage applies even in radial flow, where declining flow rates at increasing distance from the well make gravity effects especially intractable. This advantage does not apply to processes with continuous foam injection or SAG injection at fixed injection rate. Moreover, this advantage of constant- pressure SAG foam processes appears to be relatively insensitive to the details of foam behavior. In such a process, injection rate increases as foam dries out near the well and injectivity increases; as a result, most of the fixed pressure drop between wells is focused on the displacement front, with maximum suppression of gravity effects. We illustrate these effects with numerical simulations of foam displacements in 2D homogeneous rectangular alid cylindrical reservoirs.
Simulations of SAG foam processes are exceptionally sensitive to numerical artifacts. Earlier work in this area was affected by these artifacts. Some of the artifacts, and ways to control them, are discussed.
P. 491
Restriction of Gas Coning by a Novel Gel/ Foam Technique
Authors: Lakatos I. , Lakatos-Szabo J. , Kosztin B. , Palasthy Gy 
Published: December 2007

Abstract
The laboratory and field studies were focused on development of a well treatment technology which can be used for restriction of gas coning in the Algyo reservoir. The method is based on simultaneous placement of a polymer/silicate gel at the GOC and a supporting foam pillow into the oil bearing layer. Extensive laboratory studies were carried out to tailor the chemical system to the field conditions. Use of short chain alcohol and natural protein as additives improved the efficiency of chemical mechanism. Special attention was paid to implementation of the technology. Two-point injection regime was elaborated to develop a horizontal barrier between the oil and gas bearing zones. The field test resulted only in a partial success: the hydrodynamic measurement definitely shown that the barrier was correctly placed, the oil flow in the pay zone was not effected, the GOR temporarily improved and the WOR positively changed. The long-term observations are, however, discourages: the investment and the return rate of expenditure is not balanced. The Hungarian experts take a stand on extending the observation period for more cycles and to collect abundant arguments to continue or to suspend the R&D activities and the field projects.
P. 491
A Dynamic Pore-Scale Model of Imbibition
Authors: Mogensen Kristian , Stenby Erling 
Published: December 2007

Abstract
We present a dynamic pore-scale network model of imbibition, capable of calculating residual oil saturation for any given capillary number, viscosity ratio, contact angle and aspect ratio. Our goal is not to predict the outcome of core floods, but rather to perform a sensitivity analysis of the above-mentioned parameters, except the viscosity ratio. We find that contact angle, aspect ratio and capillary number all have a significant influence on the competition between piston-like advance, leading to high recovery, and snap-off, causing oil entrapment. Due to enormous CPU-time requirements we could not incorporate long-range correlations among pore and throat sizes in our network, but were limited to small-range correlations. Consequently, the gradual suppression of snap-off occurs within one order of magnitude of the capillary number. At capillary numbers around 10- to 10-, snap-off has been entirely inhibited, in agreement with results obtained by Blunt using a quasi-static model. For higher aspect ratios, the effect of rate and contact angle is more pronounced. Many core floods are conducted at capillary numbers in the range 10 to 10.6. We believe that the excellent recoveries observed during our waterfloods on tight chalk may be explained by the combined effect of rate, non-zero contact angle and existence of long-range correlations. Vast reductions in residual oil saturations are largely due to suppression of snap- off in favour of frontal displacement, whereas ganglion mobilization plays a much more modest role in the displacement of continuous oil.
P. 47
Effects of Variables on Microbial Profile Modification with Spores
Authors: Ok Lee Hae , Bae Jae H. 
Published: December 2007

Abstract
A microbial profile modification process consisting of sequential injection of spores and nutrient was reported previously. Variables affecting the efficacy of this process was studied using test-tube tests and corefloods in Berea and reservoir cores. It was found that a certain spore suspension concentration of about 107 cfu/mL is needed for effective spore propagation and plugging efficiency. A salinity above 2 wt% NaCl is needed for Salton-1 for increased permeability reduction and the time needed to achieve it. Higher injection rates, pH, and the presence of crude oil affect the degree of permeability reduction and biofilm stability. It is concluded that permeability reduction could be controlled to a significant degree by a judicious selection of nutrient package and injection scheme involving spore and nutrient concentration and amount.
P. 183
Foams for Mobility Control and Improved Sweep Efficiency in Gas Flooding
Authors: Zhu T. , Strycker A. , Raible C.J. , Vineyard K. 
Published: December 2007

Abstract
This experimental investigation studied the use of additives to enhance foam properties and improve the in-situ generation of foams for improving gas flooding sweep efficiency. Some of the parameters affecting foam performance were polymer concentration, different surfactants and their concentration, aqueous phase salinity and pH, and effect of flow rate (or shear rate).
Performance of polymer enhanced foams (PEF) was much better when compared to conventional foams. Polyacrylamide polymers were used as an additive. Higher foam resistance and longer foam persistence were achieved by using relatively low concentrations of polymers. The studies also showed that the foam performance was significantly improved over a broad range of polymer concentrations.
A number of other investigators have shown that foams are severely affected in the presence of oil. This is especially true of lighter or less viscous oils, and the destabilizing effect is magnified with a higher salinity aqueous phase. PEF with a low salinity aqueous phase showed improvement in foam stability. The effective viscosities of PEF were higher than those of conventional foams with a high salinity aqueous phase and the presence of lighter oils. Further, PEF reduced the negative impact of oils on foam mobility. Of the surfactants studied, alpha olefin sulfonates were tolerant to high salinity brines as well as being compatible with polymer additives. Other surfactants, including amine oxide surfactants, were also studied and showed unusually high foam resistance and stability.
P. 277
Calculation of Minimum Miscibility Pressure
Authors: Wang Yun , Orr Franklin M. 
Published: December 2007

Abstract
We describe and test a method for calculation of minimum miscibility pressure (MMP) that makes use of an analytical theory for one-dimensional, dispersion-free flow of multicomponent mixtures. The theory shows that in a displacement of an oil by a gas with nc components, the behavior of the displacement is controlled by a sequence of nc-1 key tie lines. Besides the tie lines that extend through the initial oil and injection gas compositions, there are nc-3 tie lines, known as crossover tie lines, that can be found from a set of conditions that require the extensions of the appropriate tie lines to intersect each other. The MMP is calculated as the pressure at which one of the key tie lines becomes a critical tie line (a tie line of zero length that is tangent to the critical locus). We describe the numerical approach for solving the tie line intersection equations, and we use slim tube test and compositional simulation data reported in the literature to show that the proposed approach can be used to calculate MMP accurately for displacements with an arbitrary number of components present.
P. 313