A systematic variation of well deliverability, as reflected from isochronal back-pressure tests performed at regular intervals, has been observed in some gas condensate wells producing at high rates. The same effects have been obtained using a numerical model of gas and condensate flow which takes into account secondary gasoline deposited in the pore space as a result of pressure reduction, and nondarcy flow of gas in the vicinity of the wells. Matching calculated values with previous test results bas been possible, and future predictions have been obtained. An application of this method to the Hassi Er R'Mel gas-condensate field in Algeria is tentatively shown. Introduction Flow capacity of gas wells is generally derived from an analysis of back-pressure tests. The empirical equation q = C(Delta p)n used by Rawlins and Schellhardt can be derived rigorously assuming that steady-state radial flow of a dry gas of constant viscosity and compressibility is established during each flow period of the well tests. Furthermore, when Darcy's law applies in the entire flow region, the theory predicts that the exponent n is equal to 1. In low-permeability reservoirs, it was soon discovered that the time required to reach a stabilized flow often exceeded the duration of the flow periods normally available for testing wells. Consequently, transient gas flow had to be considered instead of the steady-state assumption previously used. This led to the isochronal testing procedure established by Cullender which has largely replaced conventional back-pressure testing. For dry gas fields, this method yields definite values of C and n equivalent to those of the empirical equation. These values should remain constant for each well as long as the permeability of the formation and the characteristics of the gas (viscosity and compressibility) do not change appreciably. This is the case when reservoir pressure remains close to the original value and when the formation near the wellbore remains free of plugging. Under those conditions, stabilized flow potential curves of gas wells can be established from a single sequence of isochronal flow and shut-in periods. An analysis of a pressure build-up following a longer production period provides additional data on the transmissivity (kh/mu) of the reservoir, and eventually on the drainage radius rd of the well, which can be related to the value of C so that future performance of the well can be predicted using the concepts developed by A. Houpeurt. At high How rates, Darcy's law no longer applies in the vicinity of the wellbore, and inertial effects in the high velocity gas flow introduce additional pressure drops. As a consequence, exponent n of the back-pressure tests becomes smaller than 1, and a slight curvature of the log-log plot of Delta p vs q can be predicted When going from very low to high rates of flow (Elenbaas and Katz). The effects of variations of viscosity and compressibility with pressure on the radial flow of dry gas in an infinite reservoir were taken into account by Jenkins and Aronofsky. Numerical solutions of the transient flow of an ideal gas in finite radial reservoirs were presented by Bruce, Peaceman, Rachford and Rice. In the case of gas condensate wells however the presence of gasoline in the pore space as soon as reservoir pressure is reduced below the dewpoint pressure further complicates the interpretation of flow tests so that the prediction of stabilized well performance becomes very difficult. Field observation shows that both C and n derived from isochronal tests vary in time, even when reservoir pressure has not changed appreciably. Such a variation cannot be attributed to any change of the gas characteristics, and must result from the effect of a gasoline saturation on the gas flow. SPEJ P. 113ˆ

This paper describes the technical considerations that set the major design parameters for the Prudhoe Bay Miscible Gas Project (PBMGP). This project was planned as a large hydrocarbon miscible flood. The basic project concept is to manufacture a miscible injectant from the field separator off-gas. This injectant is compressed and delivered to the EOR project area for injection in a water-alternating-gas (WAG) mode. The miscible gas supply will vary, generally increasing with time. Over the first 10 years of the project, an average supply of 200 MMscflD [5.66x 10 6 m 3 /d] is anticipated. The gas processing plant and the factors affecting miscible gas supply are described. The EOR froject area was selected by a screening process. This led to a project area definition encompassing 4.9xlO RB [779 X 10 6 m 3 ] PV tontaining 2.2xI09 STB [350 X 10 6 m 3 ] original oil in place (OOIP). The planned cumulative volume of miscible gas injected will be 10% PV.Reservoir studies indicate an incremental oil recovery by miscible flooding of some 5.2% OOIP or 115x 10 6 STB [18.3X10 6 m 3 ]. Aspects of these reservoir studies are described.The Sadlerochit reservoir is both the ultimate source of the miscible solvent and the target reservoir. This introduces several reservoir/facility interaction effects. The planning of a major EOR project in the Arctic has also involved technical considerations not routinely encountered in conventional oilfield projects. Both aspects are discussed in the paper.

This reporlwas preparedas an accountof work sponsoredby an agency ofthe United States Government. Neitherthe United StatesGovernment nor any agency thereof, nor any of their Da ted : 10/31 / 91 empioy¢cs, makes any warranty, express or :,np[ied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Refer-cno= herein to any r, pccific commercial product, process, or scrvio: by trade name, trademark, manufacturer, or otherwise dots not necessarily constitute or imply its endorsement, ro_ommcndation, or favoring by the _,mited States Government or any agency thereof. The views and opinions of authors expressed herein do not neocssarily state or rvflex:t those of the United States Government or any agency thereof.

Published in Petroleum Transactions, AIME, Volume 210, 1957, pages 58–72. Abstract In the quantitative interpretation of the S.P. logs, the electrochemical component is generally taken equal to -K log Rmf/Rw, where K has the theoretical value corresponding to solutions of pure sodium chloride. This method may be misleading when relatively large quantities of salts other than NaCl are present in formation waters, - as is generally the case for low salinities, - or in gyp-base muds. In such cases recourse is made in the field to changing the K value or to adding a correction term to the equation on the basis of local experience. An investigation has been made in the laboratory of the influence of HCO3, SO4, Ca++ and Mg++ on the amplitude of the S.P. deflection, which included in particular determinations of the activity coefficients of Ca++ and Mg++. The theory, the experimental techniques and a tentative method for applying the results are described. So far, applications to actual field cases where chemical analyses of waters were available have provided an excellent confirmation of the proposed method. The case of the S.P. in very salty brines is also considered and it is shown that the use of activity data for sodium gives satisfactory results. Historical In early times of electrical logging, the SP curve was used exclusively as a tool for the location of permeable beds and the definition of their boundaries. Later, with the introduction of methods of quantitative analysis, attention was called to the possibility of deriving from the SP log some information on the formation water resistivity, which constitutes one essential element for the computation of water saturation from log data. The first laboratory experiments in 1932 had shown that, as a result of electrochemical phenomena arising at the contact of the mud and the formation, the amplitude of the deflection of the SP curve was, at least partly, a function of the salt concentration of interstitial water and accordingly of its resistivity. It was indicated that the amplitude of the electrochemical component of the SP should be equal to -K log R1/R2, R1 and R2 being the resistivities of the mud and of the formation water respectively.

Streaming-potential experiments were conducted within the Muddy- and Dakota-sandstone interval of a Denver basin well. Analysis of the data shows that, for this case, streaming potentials opposite sands were higher than those opposite shales when the mud was fresh. Streaming potentials opposite shales, however, were of sufficient magnitude to be important in SP interpretation. They were linearly dependent upon pressure differential, and they increased with mud filtrate resistivity. The magnitude of streaming potentials opposite sands was influenced by the characteristics of the original mud cake formed at the time of drilling. Use of mud samples taken at the time of logging may not always be satisfactory for determining streaming-potential corrections. Both the streaming and electrochemical potentials were found to be affected by the previous history of the borehole system. Following a change in mud characteristics, several days were required for SP stabilization. This was, in part, due to the mud cake acting as an imperfect shale membrane. Introduction Laboratory investigations by Wyllie, Salisch, Moore, Sen Gupta and Bannerjee, and Hill and Anderson have shown that streaming potentials developed across mud cakes deposited on permeable filter beds are of sufficient magnitude to be critically important in SP interpretation. Streaming potentials across shales have been reported by Schenck, Gondouin and Scala, and Hill and Anderson. The magnitude of the shale streaming potentials obtained by Schenck and by Gondouin et al led these authors to conclude that in many cases the shale streaming potential would approximately equal the mud-cake streaming potential. Hill and Anderson, however, obtained somewhat lower magnitudes of shale streaming potential. The field experiment described in the present paper was a cooperative project carried out by the respective operations and research departments of Schlumberger Well Surveying Corp., Shell Development Co. and Shell Oil Co. The primary objective of the experiment was to determine in the borehole the streaming-potential behavior of both shales and mud cakes under conditions approaching, as nearly as possible, those normally encountered in logging practice. METHODS AND EQUIPMENT WELL A Muddy- and Dakota-sandstone well in the Denver basin was chosen for the experiment. Both sandstones were water-bearing and, since reservoir pressures in these sandstones are abnormally low (gradient of approximately 0.25 psi/ft), it was expected that studies of streaming potential could be conducted from low-pressure differentials (approximately 200 psi) to about 2,000 psi by bailing mud from the hole, filling up and then applying wellhead pressure. JPT P. 305^