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Although conventional rod driven Progressing Cavity Pumps (PCPs) have been in use since the early 1980‘s, the industry has continued to seek alternative methods of powering the system. Initial attempts were made using conventional electric submersible induction motors however their high synchronous speeds proved to be problematic. These inherent high speeds resulted in developing motors with more poles (hence a slower synchronous speed) as well as down-hole gear boxes. All of this was in an attempt to get the motor speeds down to an acceptable range whereby the progressing cavity pump would work successfully. Using Submersible Permanent Magnet Motors (PMM) rather than conventional Induction Motors (IM) to drive the PCP is an effective and efficient method directly powering the PCP as well as eliminating the need for a downhole gear. In addition, the PMM motor’s power density is much higher, thus the motor length is significantly shorter which enhances deployment of the system in deviated wells. Over 1000 PCP-PMMs have been successfully installed in several Russian fields in differing applications with more than 250 still in operation. Their average run life exceeds 200 days and is typically in the range of 360-600 days with a maximum run time of 1091 days. This paper will share numerous case histories on PCP-PMM installations by providing a general review of the application, a summary of the PMM-PCP components installed and the overall design approach that led to the long term success.

The eni Petroleum Nikaitchuq field is located offshore in the Beaufort Sea within the North Slope region of Northern Alaska. The 12-1/4" intermediate section of the Nikaitchuq wells are drilled with a Rotary Steerable System (RSS) at high inclination prior to landing near-horizontal in the reservoir. The intermediate hole section passes through a very abrasive sand with an unconfined compressive strength (UCS) of approximately 22 ksi called the Lower Ugnu. Historically, the drilling of the 12-1/4" intermediate section has been drilled with two to three bit runs consisting of various polycrystalline diamond compact (PDC) and tri-cone designs. This was due to the abrasive nature of the Lower Ugnu combined with interbedded soft sand causing ledging, high stick-slip and lateral vibrations which lead to consequential bit/BHA damage and a reduction in drilling efficiency. With the objectives of drilling the section in one run and to minimize damages to the RSS and MWD, a vibration mitigation workshop was conducted between the Nikaitchuq drilling team and key service company experts. The workshop team focused on four strategies to mitigate vibrational issues: Bottom Hole Assembly modification. Introducing new technologies and tools into the drill string to capture high density data and mitigate vibration. Mapping and prediction of the hard streaks within the intermediate section. Modification of drilling practices where possible. BHA and bit vibration modeling, new vibration mitigation tools, Measurement While Drilling (MWD) and multi-axis downhole vibration measurement data, BHA and stabilizer reconfiguration, as well as implementing various drilling parameters were all investigated and applied in both the front end and at the rig site. This paper demonstrates the systematic approach the Nikaitchuq drilling team implemented to mitigate damage to the bit and downhole tools as well as improve drilling performance by minimizing stick-slip and lateral vibrations.

Near wellbore damage is often blamed for many production problems, it can manifest itself in many ways and is caused by almost anything that disturbs the formation; even producing hydrocarbons can lead to near wellbore damage. Knowing where the damage is and how it was produced can help prevent new occurrences, but oftentimes prevention is not possible. Perforation damage is one kind of damage that cannot be prevented; because the objective of perforating is to damage the formation by creating a tunnel as large and as deep as possible. A new technique of consisting of producing controlled implosions constitutes the most effective way of removing perforation and other types of near wellbore damage, and this technique lends itself to provide quantitative values of well damage removal. This paper discusses how this new technique was developed, from concept and modeling to its effectiveness in the field as demonstrated by a number of jobs on wells with different types of damage. The results are extremely encouraging; in some wells production has increased by as much as three to four times, this production increase is sustained and the rate at which well formation damage occurs is significantly lower. This paper presents field experiments conducted on four wells in the Libyan Desert, including logging data based on state of the art measurements, and giving new insights into near wellbore damage. Strategies are recommended to combat the effects of common near wellbore damage mechanisms and to address their root causes. These findings opened a debate that challenges some aspects of industry accepted perforation techniques, and presents conclusive evidence that some well damage is in fact beneficial.

Abstract The effect of liquid phase on non-Darcy gas flow through proppant packs has been characterized by correcting the non-Darcy flow Forchheimer coefficient as a function of liquid saturation in the proppant pack in the past. Through an extensive experimental study it is found that at high liquid saturation, Forchheimer correlation does not hold anymore. A non-linear relationship appears that cannot be characterized by factor alone. Tests are focused on the investigation of the effect of proppant properties (permeability and porosity), liquid properties (density and viscosity), and gas properties (density and viscosity) on the non-Darcy, two phase flow behavior. An empirical model that uses the liquid to gas ratio to predict the effective permeability or conductivity of a proppant pack under two phase, non-Darcy flow conditions is discussed in the paper. Based on the fact that proppant packs have relatively narrow pore size distributions, a simplified physical model has been developed to represent two phase (liquid and gas), non-Darcy flow through proppant packs. The purpose of developing the model is to understand the effect of gas flow on the velocity of liquid in a two-phase flow process. As a result, the model can calculate a mobile liquid saturation corresponding to each combination of gas-liquid flow rate. The relative permeability of a proppant pack at different conditions can then be calculated taking both non-Darcy and two phase flow effect into account. P. 675

Growing demand for natural gas in North America is driving the E&P industry to look for new resources in previously unexplored areas and the deep Gulf of Mexico (GOM) Continental Shelf is currently attracting a lot of attention. Several of the current deep shelf HP/HT wells have anticipated bottom-hole temperatures that significantly exceed the limits of existing MWD/LWD tools; therefore, down-hole annular pressure measurements will not be available for pressure management. This leaves temperature/hydraulic models as our best, if not our only source of down-hole pressure information. These models depend on accurate surface inputs and laboratory measured fluid properties under down-hole conditions. Unfortunately, these anticipated temperatures and pressures also exceed the operating limits of conventional HP/HT viscometers. This lack of measured fluid properties under these extreme conditions will severely limit the ability of hydraulic models to predict down-hole pressures. A new extreme HP/HT (XHP/HT) concentric cylinder viscometer was designed and built to fill this important technology gap for the GOM deep shelf HP/HT wells. The instrument is capable of measuring typical drilling fluid viscosities up to 600°F (316°C) and 40,000 psig (276.0 MPa) and is capable of accurate measurements of drilling fluid properties containing ferromagnetic materials. Subsequent verification and validation testing proved the new viscometer compares favorably to commercially available field viscometers and more sophisticated laboratory rheometers and therefore lends itself towards widespread industry use. This paper reviews the development of the instrument, automated control system and HS&E issues related to testing drilling fluids at these extreme conditions. The paper will also present results of the verification and validation testing on invert-emulsion drilling fluids.

Abstract This paper describes the methodology for incorporating uncertainties in the optimization of well count for the deepwater Agbami project. The lack of substantial reservoir description data is common in many deepwater discoveries. Therefore, the development plan must be optimized for a wide range of uncertainties. In the Agbami project, the design of experiments or experimental design (ED) technique was incorporated to optimize the well count across a wide range of subsurface uncertainties. Multiple well count development plans (high, mid, and low) were developed and used as a variable in ED. Also, multiple geologic models representing the broad range in uncertainty in oil in place (greater than a factor of two) and in net-to-gross were built and used as a variable. Additional uncertainty variables, including permeability, fault seals, and injection conformance, were studied concurrently. The ED technique allowed multiple well counts to be quickly tested against multiple geologic models. With the net present value (NPV) calculated for each case, not only was the well countfor the overall highest NPV determined, but ED allowed discrete testing of each geologic model to determine the optimum well count for each model. A methodology was developed for optimizing well count development plans over a broad range of uncertainties including a range of geologic models, which vary in oil in place and net-to-gross. The process allowed testing the robustness of any well count versus any uncertainty (or set of uncertainties). A method was demonstrated quantifying the difference between perfect and imperfect knowledge of the reservoir description (geologic model) as it pertains to well locations. A total well count of 38 was concluded to be the optimum well count for the Agbami project based on NPV. This well count proved to be robust across the full range of uncertainties tested. Introduction The Agbami structure is a northwest/southeast trending fourway closure anticline, and is located on the Niger delta front approximately 65 miles off-shore Nigeria in the Gulf of Guinea (see map in Fig. 1). The structure spans an area of 45,000 acres at spill point and is located in 4800 ft of water. The Agbami No. 1 discovery well was drilled in late 1998. The appraisal program was completed in 2001 and included five wells and one sidetrack drilled on the structure with each ncountering oil pay. These five wells and a sidetrack penetrated an average of approximately 350 ft of oil. In Phase 3 of the development process, the key objectives are to construct a field development plan and to obtain sanctioning. With drilling depths of up to 10,000 ft below mudline in 4800 ft of water, well costs at Agbami will be at the high end of typical deepwater costs. Therefore, an important optimization parameter in the field development is the total well count. Agbami is typical of many deepwater developments in that the seismic is less than perfect and the appraisal well data is sparse relative to the area coverage. Therefore, subsurface uncertainty is high.

ABSTRACT This paper presents a review of the development status of three subsea oil production systems under development by Subsea Equipment Associates Limited (SEAL). This international consortium owned by Bristish Petroleum, Compagnie Francaise Des Petroles, Groupe DEEP, Westinghouse and Mobil Oil Corporation, is presently testing two production systems designed for primary use in foreign fields. These systems should find application in the water depths greater th'an 150 feet with average well production ranging from 1, 000 to 10, 000 barrels per day. SEAL is also testing a subsea oil production in the Gulf of Mexico which is designed primarily for utilization with large numbers of domestic low-production wells which in turn generally require significant maintenance. Participating in these test projects from anon-owner standpoint are Continental Oil Company, Phillips Petroleum, Sun Oil Company and ELF/ERAP. The SEAL Intermediate System (SIS) is described with particular emphasis on utilization of a Manned Working Enclosure (MWE) to permit men to perform maintenance operations in a dry environment at the sea floor. The MWE concept involves lowering the structure over the wellhead, expelling the water and transferring personnel by the use of a Personnel Transfer Bell (PTB). The status of this development project is reviewed. The SEAL Shallow System is described including a review of present testing off the South Coast of France. This concept is similar to the MWE with the exception that the maintenance personnel are carried in the SEAL Bell. Once the bell is pulled to the subsea wellhead, water is expelled and the atmospheric pressure reduced to sea level to permit the men to enter the work chamber and perform the necessary operations. The SEAL Atmospheric System is described in some detail in this paper. This system concept is based on the use of a large habitat-type structure permanently installed on the sea floor to house oil field equipment. Future applications of this concept would be as a manifold center, a test separator center or a complete oil production system. In a similar manner to the other systems, men are transported to and from the Subsea Work Enclosure (SWE) through the use of a Personnel Transfer Bell. In addition to the description of the production SEAL Atmospheric System this paper presents a review of the present test installed in the latter part of 1972 and details are presented on the installation of the base structure, the Subsea Work Enclosure and the Wellhead Connection Assembly. The present status of this test program is also presented together with plans for the future. A common element in each of the three systems being developed by SEAL is the use of a Personnel Transfer Bell to transport maintenance workers to the subsea structure in a safe and efficient manner.

Exploration and production in deep water has been a challenge to oil industry over the last years. To develop fields in over 1000 meters water depth, Petrobras had contracted most of the total fleet of Dynamic Positioning – (DP) rigs around the world and also anchor handling and special purpose vessels. Work-over operations as well wet Christmas trees installation and the deployment of manifolds and pipelines have been carried out at same time in a small area. The operation scenario can be a target circle of 5 km radio, which can comprise four rigs and others DP vessels operating at the same time. The purpose of this paper is to report how we have managed to control this critical situation and reduce the interference among the acoustic positioning systems of these vessels. For that reason, we have been assuming new technical and administrative procedures. In deep waters the signal to noise ratio at the surface transducer is the critical point. Because of the high nominal ranges required in this application, the acoustic bandwidth is very narrow, less than 30 kHz. The interference problem became more critical during the ionosphere scintillation periods, when the rigs positioning system relied solely on acoustics systems. By controlling the acoustic environment and looking for new technologies, we think we are hoping to reduce this kind of problem. The paper shows how we have controlled the acoustic environment in those areas of interest and how we have plan operations to reduce the possibility of an accident. In addition it also shows graphics and tables that will help the reader to fully understand what we have done.

1. ABSTRACT Environmental issues such as global warming are getting widespread international attention. Flare Gas Elimination projects and Flare Gas Recovery systems become more interest among oil and gas industries all over the world. Screw compressors are suitable for gas compressor applications that can recover flare gas or the hydrocarbon vapor instead of sending it to a flare line for offshore platforms or FPSOs (Floating Production, Storage, & Offloading). This type of compressor system provides Zero Flare Emission. Oil-free screw compressors have been used for process gas applications since the 1970's. Oil-flooded screw compressors have been used in many process gas related applications since the 1980's. Recently, both oil-free and oil-flooded screw compressors have been expanding into the process gas compression application industry. The oil-free screw compressor is popular for the offshore applications in recent market trends, and it has been used due to several advantages, good suitability and reliability in comparison to other types of compressors. Hybrid Screw Compressors have been developed by creating the best combination of advantages in the oil-free and the oilflooded screw compressor. Hybrid Screw Compressors have good features of compact and reliable designs, simple single skid arrangements. These features translate into benefits for the users such as lower installation costs, simple and easy start/stop operation, and suitable for long-term continuous operation. 2. INTRODUCTION The purpose of this paper is to present technical information and advantages in Hybrid Screw Compressors, and also show a comparison to the conventional type of Oil-free and Oil-flooded Screw Gas Compressors. In addition, the paper will explain what benefits the Hybrid Screw Compressor provides to vapor recovery and flare gas elimination applications in the offshore areas. 3. HISTORY Since the screw compressors have characteristics of both rotary (centrifugal) compressors and positive displacement compressors (reciprocating), screw machines found rapid acceptance in petrochemical and gas processing industries. In 1975, API 619 was introduced to specify a screw compressor. This first edition of API 619 looked only at oil-free screw compressors. During this period, the oil-free screw compressor was applied in many unique applications such as butadiene, styrene monomer recycle gas, linear alkyl benzene, soda ash, etc. Most of these applications are subject to dust, polymers, and liquids that are likely to be present in the gas stream. In many cases, water injection was used to control the compression process. In the 1980's, oil-flooded screw compressors started appearing in process gas applications. During the same period of time, cogeneration started to take off with gas turbines becoming necessary in more and more applications. Also, oil-flooded screw compressors were finding their way into light gases such as Helium and Hydrogen.

Abstract This paper describes the design of a well system for development drilling from a Spar(1). In particular, the paper gives results of realistic well control modeling which has been used to confirm the design specifications for a system consisting of a surface BOP, pressured riser and partial seabed BOP (split BOP). Details of the pressures that would be expected from typical Gulf of Mexico (GOM) deep water well kicks will be given. The results of the work show:Most kicks that will be encountered can be dealt with using a pressured riser and a surface BOP if this riser is rated to 3000 psi for surface holes and 6500 psi for deeper hole sectionsA seabed choke and seabed BOP may be used under certain circumstances to limit riser pressures The well control system as conceived also allows for:More effective deep water drilling when compared to a "conventional" subsea drilling system - casing strings can be pushed furtherA dual barrier such that failure of the riser during drilling does not result in a blow-outMany areas for potential cost savings when compared with a "conventional" subsea drilling system The system is designed to fit the capabilities of a Spar. The paper also shows how the design of the well system leads to some cost savings for the Spar system as a whole. Introduction Up until now, drilling operations in the ultra deep waters of the Gulf of Mexico have generally been carried out using a "conventional" drilling system consisting of a seabed (subsea) BOP and a non-pressured marine drilling riser. If a kick occurs, the seabed BOP is closed. The kill circulation path is through the drillstring to the bit, up the well annulus to the seabed and then through the choke or kill line (or both) to the choke manifold located on or close to the drilling rotary table. This type of system has its merits but also its drawbacks which include:Significant friction pressures which are transmitted back through the well when circulating through the long choke and kill linesComplex seabed equipmentPotential high gas rates at the surface resultant from small undetected swabbed kicks (subsequently circulated through the riser) when synthetic oil base mud (SOBM) is in use(2) The work described in this paper used a realistic well control simulator (RF Kick)(3) and an underbalanced drilling simulator (RF Dynaflodril)(4) to examine an alternative well system that could be used from a Spar and that would:eliminate (for the most part) the drawbacks of the "conventional" systemprovide all required well control capabilitiesallow for cost effective drilling. Several key requirements had to be met. These were:Ability to deal with the pressures and other conditions that are likely to occurAbility to be able to deal with a catastrophic event (for example, evacuation of the wellbore following a well flow that has gotten out of control)Provision of a back up such that a single point failure does not cause the loss of the well

Knowledge of the regional state of in situ stress direction and magnitude is required to delineate stress provinces, to analyze intra plate earthquakes, to optimize petroleum recovery and for the development of civil projects in rock masses. This paper on rock mechanics and reservoir geomechanics studies the stress state including the pore pressure that operates in the rock mass and the mechanical behavior of the rock, to create an integrated model to study the in situ state of stress in the Eastern Cordillera, Colombia. Several measurement techniques were used, which include strain-relief overcoring, hydraulic fracturing techniques, shear fractures in the walls of the boreholes knows as breakouts, leak off test and induced drilling tensile fracture in the walls of the boreholes. Rock mechanics properties are required for the application of these methods and laboratory tests were carried out to find elastic constants. The orientation of the maximum horizontal principal stress σHmax is parallel to that of tensile failures (tensile wall fractures) and perpendicular to that of compressive failures (breakouts). The magnitude of the minimum principal horizontal stress σhmin is determined from leak off tests (LOT) and hydraulic fracturing, while the magnitude of the vertical stress σV is simply calculated based on the density data collected in several representative wells in the Cusiana field. From recent tectonics results are clear that the region in the Eastern Cordillera is characterized by an active strike-slip / thrust faulting regimen. The actual regional state of stress found means that the minimum principal stress σhmin (0.65 psi/ft to 0.77 psi/ft) oriented in a NE-SW direction, is less than the vertical stress (1.07 psi/ft), and the maximum principal stress σHmax (1.2 psi/ft to 1.7 psi/ft) in NW-SE compressional direction is significantly greater than the vertical stress, which therefore is the intermediate principal stress.

Abstract This paper describes parallel linear solvers of LSOR and preconditioned ORTHOMIN (K) on parallel computer based on T800 Transputers and SUN workstation cluster (with Ethernet network). Both Algorithms show a high degree of parallel efficiency on Transputers, whereas only full implicit method and large petroleum reservoir problems can observe a high efficiency on SUN workstation cluster. The key issue in parallelization of reservoir simulator on workstation cluster is the improvement of communication speed. Introduction Petroleum industry is among those that first introduced computer technology, and is also the area where computer technology is adopted thoroughly and popularly. Reservoir simulation is one of the most powerful tools for analysing the complicated fluid flow within a reservoir today. Engineers frequently use reservoir simulation to find out production performance of entire reservoir, and work out development plans scientifically. Distributed memory parallel computer and workstation cluster are two hot spots in computer industry today. It is attracting more and more attention as how to use these computers to solve practical problems requiring large computation. Numerical reservoir simulation, requiring large computation and has relatively high degree of parallelism and modest I/O requirement, therefore the distributed memory parallel computer system is suitable for such purpose. But most existing reservoir simulators are based on sequential computers and must be restructured to make full use of the capability of these computers. P. 505

Introduction During the past ten years the petroleum industry has been expanding rapidly to meet a major increase in the demand for its products. This expansion, carried on during periods of manpower and materials shortages, has required maximum efficiency in the exploitation of existing resources, and a vigorous campaign to locate and develop new resources. In such an unprecedented program of increasing production under adverse economic conditions certain problems, formerly considered of negligible importance, have become particularly troublesome. One such group of problems is the weather and oceanographic difficulties that are encountered through the gamut of petroleum operations, from management planning, through production practices, to the delivery of products to the consumer. Experience acquired in working on these problems during the past six years indicates that the amount of money involved incorrect decisions vs. incorrect decisions where weather and oceanographic conditions are a factor is of significant decisions where weather and oceanographic conditions are a factor, is of significant economic importance. This paper endeavors to indicate the economic scope of the weather and ocean problems in the petroleum industry, and summarizes some of the experience gained in attempting to arrive at an efficient method of attacking these problems. Scope Of Weather and Ocean Problems The following list summarizes some problems that have arisen during the past several years. The list is broken down into categories according to the departments in which the project was carried on.ProductionDesign studies for coastal and offshore facilities48-hour operational weather and sea forecasts for planning and safety in offshore construction, drilling and production.Weather and oceanographic instrumentation for developing design data for coastal and offshore drilling.Hurricane evacuation problems.Radar weather warnings (line squalls and northers)

Abstract In reservoir analysis important quantities such as reservoir pressure, in-place oil, and well damage are calculated from directly measured quantities and each measurement error has an effect on the calculated result. This paper employs statistical methods in the quantitative consideration of the effect of these measurement errors on answers calculated by specific formulas which may be taken as typical of reservoir engineering calculations. Detailed studies have been made concerning reservoir pressure, reservoir pressure decline, initial in-place gas in distillate fields, initial in-place oil in unsaturated fields, initial in-place oil in solution gas drive fields, and well damage. A wide range of examples is presented so that the conclusions may be generally applicable. Various intangible factors which cannot be included in the equations limit the quantitative applicability of the calculated error, but these factors reinforce rather than detract from the conclusions. Particular attention is given to the effect of bottom hole pressure measurements errors. The overall conclusion from this study is that in nearly all cases the errors in bottom hole pressure measurements make the major error in reservoir engineering calculations and that in many instances an increased accuracy of the pressure instruments to ±1 psi is highly desirable. Introduction The question of what accuracy is required in the data assembled for the purpose of making reservoir analyses has been the subject of much discussion in the past. Extremes of opinion have been encountered, ranging from a belief that reservoir analysis is approximate at best and that very approximate data are sufficient to an insistence that all factors be measured to the utmost possible precision.

Abstract During late 1950 and up to present date in 1951 the Spraberry sand production of West Texas has created wide-spread interest in the oil producing industry. It is recognized that there are many controversial opinions concerning operations in the Spraberry, it's economic value, and future development. The application of Hydrafrac procedures to completion of Spraberry wells has become prominent in the development of these sands. This paper outlines the geologic and historical development of the Spraberry and the use of Hydrafrac applications in these formations. Introduction The application of the Hydrafrac Process to wells completing from the Spraberry formation was begun during the last part of 1950. The Hydrafrac Process consists of preparing a viscous gel to which a special sand is added and pumping this material into the producing formation at a rate which will develop sufficient hydraulic force to produce and/or extend a fracture. The gel must be of an unstable character to revert to a thin fluid, such that it may be recovered from the well, leaving the introduced sand in the fracture as a propping agent. In order to insure the reversion of gel to a fluid, breaker chemicals are mixed with crude oil and flushed into the formation behind the gel. The success of these treatments has been closely associated nth the current expanding drilling and development program along an area commonly referred to as the Spraberry Trend. 'Top of Spraberry' is found at depths of 6,500 to 7,500 feet in most of this area. This trend covers an area over 100 miles in length and 50 miles in width from the North Gail Field of Borden County to the Flatrock Field of Upton County. Location of this eight county area of West Texas is shown in Figure 1.Location of the fields discovered through June 1951 are shown in Figure 2.

Published in Petroleum Transactions, AIME, Volume 195, 1952, pages 285–288. Abstract This paper describes an improved acidizing technique which has been applied in acidizing gas wells in the La Gloria field. Wells acidized in this manner exhibited a much greater increase in deliverability than wells acidized in the conventional manner. The acid is injected into the well in small slugs separated by a small volume of high pressure gas. The acid and gas are displaced from the tubing by high pressure gas to reduce the hydrostatic head on the well when the acid is recovered from the well. The well is opened for production as soon as the acid and gas are displaced. This procedure permits a very rapid recovery of the acid which results in large increases in the deliverability of the gas wells. It has been found advantageous in the acidization of gas injection wells to inject the high pressure gas directly after the acid without backflowing the acid out of the well. This practice has made it possible to inject the gas in the injection wells of this field with a much lower pressure differential. This reduces the horse-power required to inject the gas and also decreases the number of injection wells required per reservoir. Introduction Results obtained by acidizing gas wells in the La Gloria field have varied considerably in the past. For this reason, a planned study of the acidizing procedure was undertaken in order to obtain more consistent results. The Frio Sands of the La Gloria field are rather permeable and it was not necessary to acidize many of the wells when they were originally completed. At the completion of an eight year cycling program in several of the gas reservoirs, it became necessary to recomplete many wells in other reservoirs. It was found that the open flow potential of the wells recompleted in different sands was not as large as wells that were originally completed in that reservoir. A study of the drilling records of several of these wells indicated that the sands had originally been subjected to considerable hydrostatic drilling fluid overload while the well was being drilled to the deeper sands of the field. It is indicated that during this eight year period, the drilling mud and water that were lost into the formation when the well was being drilled had formed a relatively impermeable zone around the well bore. This impermeable zone around the well bore made it very difficult to obtain high deliverability wells when the original wells are recompleted in other zones.

Abstract One of the important functions of the petroleum engineer is the volumetric analysis of the reservoir for an estimate of in-place oil. The reliability of the estimate is a joint function of the accuracy of basic data used and of the correctness of application. Frequently, basic data are obtained from laboratory determinations of porosity and interstitial water saturation. It follows that errors in laboratory measurement may have a serious effect on reservoir evaluation. A better understanding of the methods used, of the variables that affect it, and of consistent variations that tend to yield high or low results will allow the laboratory worker to produce more accurate values. Similarly, a better understanding on the part of the engineer will permit him to use the data more intelligently so that unavoidable errors may be corrected rather than compounded, and so that an increased reliability of reservoir evaluation may result. This paper presents the results of investigations of variables which may lead to errors in some standard porosity methods, and in the restored-state [disc] determination of interstitial water. Variables of preferential wettability, clay hydration and gas adsorption are shown to be interrelated in their effects. Additional variables related to equipment, technique, capillary pressures, fluid phases and calculation procedures are considered. It is shown that a report would more properly present porosity available for hydrocarbon storage than simply porosity and interstitial water content. Data obtained statistically from a quantity of restored-state and routine core analysis work are offered as supporting evidence. The variables are each treated individually, so that each may be understood separately, as well as in its interrelationship with others. Introduction The restored-state concept has been widely utilized as an indirect approach to petroleum reservoir evaluation. The term denotes a laboratory simulation of reservoir processes of oil accumulation and production in a sample of reservoir rock. Determination of interstitial water has been a primary concern of restored-state work during its relatively short life. Publications have dealt with variously devised interstitial water methods and modifications of methods. In one particular aspect much of the reported work has been somewhat idealized in that implicit assumption has been made that porosity measurement is not a problem as associated with determination of interstitial water. In this paper, consideration is given variations between some usual porosity methods which are utilized in routine core analysis and restored-state work.

Published in Petroleum Transactions, AIME, Volume 195, 1952, pages 289–296. Abstract The internal surfaces of rocks which are in contact with interstitial fluids are known to influence in some degree the recovery of hydrocarbons from pay zones. Despite the admitted importance of the influence of solid surfaces on hydrocarbon recovery, little information is available concerning the extent of surface of reservoir rocks. In this paper a description is given of the apparatus and procedure employed in the determination of the surface areas of sedimentary rocks, and values are reported for a variety of sandstone and limestone cores. In addition, consideration is given to the Kozeny equation, which relates surface area to porosity and permeability. A comparison is made between the surface areas as calculated from this equation and the geometrical areas of a series of packs of spherical glass beads. Also, for a group of sandstone cores, Kozeny areas are compared with surface areas as determined by the gas adsorption method employed in this investigation. Introduction It has long been recognized that many processes which are of importance to hydrocarbon production are controlled in some degree by the extent of the surface of the reservoir rock through which the hydrocarbons move. For example, the recovery efficiency that is obtained in a given reservoir is certainly determined in part by the action of interfacial forces between the reservoir fluids and rock, and this action is influenced in turn by the extent of solid surface. Despite the admitted importance of surface effects to problems of petroleum recovery, little information is available concerning the extent of surface of reservoir rocks. A recent paper by Kulp and Carr reports surface areas of deep-sea sediments. Their values are in general much higher than those reported herein for reservoir rocks probably because of the high clay and silt content of the sediments. It is the purpose of this paper to describe an apparatus which has been employed for the measurement of the surface areas of rock samples and to present the values which have been obtained for a variety of sandstone and limestone cores. In addition, the relationship of surface area to permeability and porosity, as given by the Kozeny equation, will be discussed.

The purpose of this paper is to sum up for you the economic point to which our technological progress in reservoir engineering has brought us; to analyze some of the current obstacles to more rapid progress; and to point out the broader responsibilities in the area of executive work that are more and more being opened to engineers. With this group there is no need to trace the beginnings of reservoir engineering, nor to emphasize the accelerating rate of growth of our knowledge and understanding of its principles. Today reservoir engineering and it concepts are an accepted branch of oil producing technology; accepted by producers, by regulatory bodies, and by the courts. Its principles are inextricably woven into the general concept of oil and gas conservation. In fact the legal basis for acceptance of its findings by regulatory bodies and courts of law rests largely on the concept that application of reservoir engineering principles will result in conservation of oil and gas resources for the welfare of all the people. Only a few of the new crop of engineers each year are unaware of the importance of economics in the practical application of reservoir engineering principles. The rest of you learned because management executives were always scrutinizing projects and laying down the law about the economic practicality of various proposals. But that situation is changing rapidly these days. Many engineers are themselves part of management; others are in the process of being trained to become part of management. Therefore the detailed screening of the economic phases of reservoir engineering projects is being done more and more by engineers themselves. Top executives are apt to check only the overall figures and conclusions. This is a highly desirable trend. But if it is to continue and accelerate, then engineers must become more executive minded in their thinking about the practical economics of reservoir engineering projects. They must display a willingness to accept responsibility for checking broader aspects and longer term phases of economic problems. Let me cite an example of executive minded thinking about conservation projects. For many years now the elimination of flaring of casinghead gas has been recognized as a highly desirable conservation objective. Literally hundreds of people have talked and written about the subject. Less than 10 years ago, two distinguished authorities in this field were testifying before a Federal Power Commission hearing on gas in Houston. Here is the gist of what they told the Commissioners at that meeting. A price of 10 cents per thousand for gas at the well head will do more to stop waste and achieve true conservation than all of the actions of all the regulatory bodies in the country, plus all the public agitation on the question. Subsequent developments in gas prices and conservation results have served to emphasize the sagacity of these two men.

Introduction The Lake Centralia-Salem Oil field, Marion County, Ill. was formally unitized September 1, 1930 for simultaneous water flooding of five pay horizons. The engineering and operational aspects of the formation of the Salem Unit have been discussed by Love. Geology of the field has been presented by Arnold. The unitized field embraces an area of 8,800 acres approximately 6 1/2 miles in length and 2 1/2 miles in width. The field has produced 222,000,000 bbl of oil while some 15,000,000 bbl remain to be produced by primary methods. It is estimated that the ultimate secondary oil recovery will be approximately 85 per cent of that recovered under primary production. The magnitude of this project may be appreciated when it is realized that accumulated injected water will be of the order or 1,680,000,000 bbl during a 20 year flood life. At peak conditions the total injection requirements may reach 350,000 B/D. The proper selection of surface facilities for a project of this size presents a multitude of complex problems. Careful consideration must be given to the economic aspects of each phase, not only in equipment and construction, but also from the standpoint of operational costs. It is the purpose of this paper to present a discussion of the equipment and facilities that have been installed in the Salem Unit to accommodate the secondary recovery operations. Figure 1 shows a diagrammatic flow plan of flooding facilities. Water Supply The field was producing approximately 8,000 B/D of salt water at the time of unitization. It was estimated that a maximum water injection requirement of nearly 350,000 B/D would be reached during life of the flood for all formations. Considering time for flood development, field water production, etc., it was further estimated that make up water of approximately 185,000 B/D would be needed to meet this requirement. Extensive investigations were conducted in the immediate and surrounding areas of the Salem Pool to determine the most satisfactory source of water. From these investigations it was concluded that the most economical source of water would be from fresh water gravel terrace deposits along the Kaskaskia River approximately 17 miles northwest of the field. In these investigations, consideration was also given to the possibility of developing a salt water supply from aquifers of 1,000 ft to 1,500 ft depth in field area, but the economics of such a source were not favorable because of the large anticipated volume requirements. It was estimated that development and operating costs of the fresh water source to produce 185,000 B/D would be about 60 per cent less then that of the salt water source.