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SummaryThe objective of the study was to test the effect of a direct fed microbial (DFM) on the performance of broilers compared to an antibiotic growth promoter under large scale, commercial production settings. Three dietary treatments were tested in a completely randomized design including: 1) a control (C) diet containing 500 FTU/kg phytase and a mixture of xylanase, amylase, protease ; 2) C+ a specific three-strain combination of Bacillus spp. (DFM) and 3) C+ bacitracin methylene disalicylate (BMD). Six, similar commercial broiler houses (15,300 birds per house) were used to give two replicate houses per treatment. The birds (Hubbard x Cobb500) were fed pelleted and crumbled diets ad libitum throughout the 44 day trial period. Due to the large scale, commercial nature of the trial, no significant differences were observed in production parameters among treatments, except that DFM treatment resulted in significantly lower mortality numbers in the last two days (43 to 44d) compared to the control. However, the DFM treatment group showed numerically higher live bodyweight, lower feed conversion ratio (corrected for body weight and mortality) and lower total mortality weight compared to either the control or BMD groups, resulting in an improved production efficiency factor. When compared to control, using DFM resulted in a gross benefit of US$ 0.06 /bird, while using BMD was not cost effective. In conclusion, DFM containing a three-strain combination of Bacillus spp. may be used as an alternative to antibiotic growth promoters, resulting in economic benefit under commercial production settings in broilers fed commercial diets.

Thomas, L.K.; SPE, Phillips Petroleum Co. Phillips Petroleum Co. Dixon, T.N.; SPE, Phillips Petroleum Co. Phillips Petroleum Co. Evans, C.E.; SPE, Phillips Petroleum Co. Phillips Petroleum Co. Vienot, M.E.; SPE, Phillips Petroleum Co. Phillips Petroleum Co. Copyright 1987 Society of Petroleum Engineers Summary. This paper describes the evaluation of a waterflood pilot in the highly fractured Maastrichtian reservoir of the Ekofisk field in the Norwegian sector of the North Sea. A four-well pilot consisting of one water injector and three producers was initiated in Spring 1981 and was concluded in mid-1984. A total of 21 × 106 bbl [3.3 × 106 m3] of water was injected, and water breakthrough occurred in two of the production wells. Simulation of waterflood performance in the pilot was conducted with a three-dimensional (3D), three-phase dual-porosity model. Initial and boundary conditions were taken from a full 3D single-porosity model of the reservoir. The pilot was conducted to determine the following information for the Maastrichtian: water-cut performance vs. time, water imbibition characteristics, and anisotropy. Results from this work have been incorporated into a full-field waterflood study. Reservoir description included the determination of fractured areas, matrix block sizes, water/oil capillary imbibition, matrix permeability and porosity, and effective permeability. These data were derived from porosity, and effective permeability. These data were derived from fracture core analysis, pressure transient tests, laboratory water/oil imbibition studies, repeat formation pressure test results, and open- and cased-hole logs. An excellent match of waterflood performance was obtained with the dual-porosity model. Of particular interest are the imbibition characteristics of the Maastrichtian in the Ekofisk field and the character of the water-cut performance of the producing wells following injector shutdowns and startups. Introduction The Ekofisk field was discovered in Nov. 1969 in Block 2/4 of the Norwegian sector of the North Sea. The field is a north/south-trending anticline located about 160 miles [257 km] from land in about 240 ft [73 m] of water. In July 1971, production began from four subsea wells. These were later abandoned in 1974 when production began through permanent facilities. Field production peaked in Oct. 1976 at about 350,000 STB/D [55 600 stock-tank m3/d] and currently averages 110,000 STB/D [17 500 stock-tank m3/d]. Original oil in place (OOIP) in Ekorisk is estimated to be 6.7 × 109 bbl [1.1 × 109 m3]. The reservoir consists of about 600 ft [180 m] of productive limestone that can be divided into the Ekofisk productive limestone that can be divided into the Ekofisk formation (Danian Age), approximately 400 ft [120 m] thick, 50 to 90 ft [15 to 30 m] of dense limestone and a 200-ft [60-m] -thick section of highly fractured Tor formation (Maastrichtian Age). The reservoir rock is naturally fractured, with fracture intensity increasing with depth. The reservoir was overpressured initially and contained an undersaturated oil at an initial pressure of 7,120 psig at 10,400 ft [50 MPa at 3170 m] subsea. The psig at 10,400 ft [50 MPa at 3170 m] subsea. The bubblepoint pressure was approximately 5,545 psig [38 MPa] at a reservoir temperature of 268 deg. F [131 deg. C]. Initial solution GOR at producing separator conditions was 1,530 scf/STB [276 std m3/stock-tank m3]. Table 1 presents a summary of the Ekofisk reservoir parameters. The field was developed with three production platforms. Produced gas in excess of sales gas has been platforms. Produced gas in excess of sales gas has been reinjected into the Danian formation in the crest of the field. Oil produced from the field is sent by pipeline to Teesside, England, and gas production is transported by pipeline to Emden, Germany. As of Jan. 1, 1984, a total pipeline to Emden, Germany. As of Jan. 1, 1984, a total of 690 × 106 bbl [110 × 106 m3] of stock-tank oil and 2,263 Bcf [64 × 109 m3] of gas have been produced. Gas reinjection totals 621 Bcf [17.6 × 109 m3]. Primary oil recovery with excess gas injection is forecast to be about 1.2 × 109 bbl [190 × 106 m3] or 18% of the OOIP. A Maastrichtian pilot waterflood was initiated in the Ekofisk field in April 1981 to evaluate the performance of water injection in this highly fractured formation. The four wells that make up the heart of the pilot are B-16, of water injection well, and B-19, B-22, and B-24, the three closest Maastrichtian-only producers. Both model and laboratory studies were undertaken to assist in the evaluation and interpretation of waterflood results. The model study of water injection into the Ekofisk Pilot, which is located in the Platform B area of the field, Pilot, which is located in the Platform B area of the field, was conducted with a dual-porosity model. An analysis of available data was made to determine fractured zones in the pilot area, and only those areas were assigned dual porosities. History for this study consists of the period from Jan. 1, 1978, to April 1984 and includes a total pilot water injection of 21 × 106 bbl [3.3 × 106 m3]. pilot water injection of 21 × 106 bbl [3.3 × 106 m3]. During the injection period, 107 STB [1.5 × 106 stock-tank m3] of oil and 38.2 Bcf [1.1 × 109 m3] of gas were produced from the three pilot producers. produced from the three pilot producers. Initial conditions for the study were taken from a 3D history match of the field. The area selected for inclusion in the study is about 1,100 acres [445 ha] and includes five edge wells-B08, B-14, B-18, B-21, and B-23- in addition to the primary pilot wells. JPT P. 221

This paper (SPE 51396) was revised for publication from paper SPE 36753, first presented at the 1996 SPE Annual Technical Conference and Exhibition, Denver, Colorado, 6-9 October. Original manuscript received for review 24 October 1996. Revised manuscript received 23 October 1997. Paper peer approved 7 July 1998. Summary This paper presents the calculation of near-wellbore skin and non-Darcy flow coefficient for horizontal wells based on whether the well is drilled in an underbalanced or overbalanced condition, whether the well is completed openhole, with a slotted liner, or cased, and on the number of shots per foot and phasing for cased wells. The inclusion of mechanical skin and the non-Darcy flow coefficient in previously published horizontal well equations is presented and a comparison between these equations is given. In addition, both analytical and numerical solutions for horizontal wells with skin and non-Darcy flow are presented for comparison. P. 392

Summary This paper describes the development and application of a comprehensive wellperformance model. The model contains six distinct sections: simulation design, tubing and/or casing flow, reservoir and near-wellbore calculations, productionforecasting, wellbore heat production forecasting, wellbore heat transmission, and economics. These calculations may be performed separately or in anintegrated fashion with data and results shared among the different sections. The model analysis allows evaluation of all aspects of well completion design, including the effects on future production and overall well economics.production and overall well economics. Introduction The well performance model can evaluate completion design alternatives andpredict well performance. The model consists of six distinct parts: hydraulicfracture modeling, well completion evaluation, gas backpressure analysis, production forecasting, wellbore heat transmission, and economic evaluation. These separate functions have been integrated into a single package thatprovides sharing of data and results. The provides sharing of data and results. The model features interactive input with on-line help, data checking, and unitconversion. This work describes the engineering calculations used in the modeland illustrates the results that can be obtained In the following sections thesix major parts of the well performance model are parts of the well performancemodel are developed. Hydraulic modeling is discussed with a 2D fracturegeometry model. The model can predict the behavior for either proppant or acidfracturing. Well completion evaluation is performed by plotting both reservoirinflow and tubing flow plotting both reservoir inflow and tubing flow curves ona single plot. Equations are developed to account for the wide variety oftubing, near-wellbore, and reservoir effects that can be modeled. Theconstruction of wellhead, bottomhole, and transient backpressure plots formonitoring well performance or predicting deliverability is performance orpredicting deliverability is described. These plots can be constructed frommultipoint field test data, well-test-derived skin, or full specification ofthe well completion design. Production forecasting is performed by combiningtransient and pseudo-steady-state analytical solutions with pseudo-steady-stateanalytical solutions with a single-cell material balance. Single-phase gas andoil or two-phase gas/oil production can be predicted. The effects of waterinflux on the production forecast is developed. Also, a simple multicell coningproblem is constructed to illustrate the workstation's ability to submitcomputer intensive jobs to a supercomputer interactively. The program also canrun domestic or international economics. The calculation of wellboretemperature profiles and the prediction of hydrate f are described. Examplesillustrate the model. Stimulation A 2D hydraulic fracture model, which can predict both propped and acidfracturing is predict both propped and acid fracturing is incorportated in thewell performance model. The model uses a modified Geertsma and deKlerkformulation to describe the behavior of the linear, 2D fracture. Thisformulation predicts width and length assuming a rectilinear propagation of thefracture from a line source. The model is based on the program developed by Rybicki et al. For the program developed by Rybicki et al. For the U.S. DOE. Rybiciki et al. extended the original work of Geertsma and deKlerk to includenon-Newtonian fluids, fluid leakoff, mill proppant transport. The total fluidleakoff is cal internally or may be entered directly. Fracture height is set bythe user and normally is greater than the pay height. The proppant transportmodel allows different proppants to be used in different stages. Thepredictions of this model are highly dependent on the proppant settlingcalculations used. The model of Acharya is used exclusively in the wellperformance model. Thirty-eight proppants are supported by the program. Theprogram has been modified to estimate dimensionless fracture conductivity assuggested by Economides and Nolte. The suspended (slurry) and settled (bed)concentrations of proppant contained in the pay zone are obtained first. Thecell concentration (in pounds proppant per gallon is combined with the fracturewidth modeled for that cell to obtain the propped concentration (in pounds persquare foot). The dimensionless fracture conductivity then is obtained on acell-by-cell basis. These cell conductivities are averaged to obtain thefracture conductivity. Tables of proppant data are used to provide therelationship between concentration of proppant, closure stress, and thefracture conductivity. The closure stress is taken to be constant along thefracture and is calculated as the difference between the bottomhole treatingpressure (BHTP) and the bottomhole flowing pressure (BHTP) and the bottomholeflowing pressure (BHFP) when the well is put on pressure (BHFP) when the wellis put on production.