Abstract Obtaining a reliable early warning of a potential risk of explosion or fire event is a major desire for the Petrochemical, Gas, Oil and Fuel Industries in general and especially the offshore platforms. Unwanted fuel spills of fugitive vapor clouds, migrating along congested pipelines and hot production areas, may accumulate in enclosed areas (traps) or mix with the air to form flammable air fuel mixture that in the presence of an ignition source causes a deflagration to detonation process. A method and apparatus for detecting flammable and toxic atmospheres are described in the present paper. The method is particularly useful for detecting flammable hydrocarbon vapors in hazardous areas such as: tank farms and storage areas of petrochemicals, engine rooms where leaks of fuels create an explosion and fire hazard, migrating flammable clouds from production/storage! transportation sites. The method employs remote sensing electro-optical means and uses spectral analysis to detect and identify the presence of flammable vapors, differentiate between paraffin's and aromatics, toxic gases or obscuration conditions, as well as identify the outburst of flames at their ignition time. Various atmospheric conditions (fog, rain, snow) as well as false alarm stimulus (radiation sources, smoke and particles) are discussed and test results on laboratory and field scales up to 100 meters detection range are presented. The novel optical open path gas detection technology has gained a lot of interest since the late 80's and in recent years, due to technical improvements, installations have been made by British Petroleum (B.P.) Phillips Petroleum, Shell. Typical installations of SAFEYE ™ and SHARPEYE ™ on offshore platforms are presented in this paper. Introduction The Petrochemical industry and especially the offshore industry are well aware of the high risk of some of the processes and the safety procedures required to protect the expensive and sometimes irreplaceable equipment and personnel. In safety applications, gas detection should be used to warn that a hazardous amount of gas may be present in an area. Often it is not important to detect a local leak because it is either too small to threaten safety or may result in flash fires which can be detected and extinguished on time with proper fire hazard management. Present fire hazard management includes state of the art "Triple IR" optical fire detection technology that provides very fast and accurate fire detection. This technology utilizes the infrared emission spectrum of flames and analyzes it versus background radiation using 3 IR selected channels. The following flame detection survey summarizes the existing technologies employed in flame detection, their limitations and future trends. U.V FLAME DETECTION The U.V spectral band because of its short-wave characteristics is absorbed in the surrounding atmosphere by air, smoke, dust, gases and various organic materials. Hence, U.V solar radiation dispersed in the atmosphere, especially at wavelengths shorter than 300 nm (the solar blind spectral band) being absorbed by the surrounding atmosphere, will not create false alarms for the flame detectors using this technology. The U.V spectral signature of the flame has a pattern that can be readily recognized over the background radiation.

Abstract The Underground Test Facility (UTF) is producing from three tunnel drilled 500 meter long horizontal well pairs which have produced effectively at their peak rates and reached recoveries of almost 55% 00IP. Two new pairs of 750 meter and 300 meter horizontal wells have been drilled from the surface and were started up in April 1996. Start-up performance and well control methods have been successful. Another 750 meter horizontal well pair is to be drilled from surface in the spring of 1997 and started up in the fall of 1997. Its purpose is to test methods of operating a well pair next to a depleted reservoir without losing steam to it. Net revenue from the UTF Project has funded the costs of adding three surface well pairs and related plant facilities since September 1994. The UTF Project is owned by AOSTRA with nine industry participants, including Gibson Petroleum Company Limited who was appointed Project Operator in October 1995. Introduction This is the third in a series of papers presenting the development status of the Steam Assisted Gravity Drainage (SAGD) process at the Underground Test Facility (UTF) situated 70 kilometers northwest of Fort McMurray, Alberta (Figure 1.1). The first paper 1 , presented in 1991, covered the initiation of the UTF Project from 1984 to May 1991. It discussed the rationale for starting the UTF, the basic SAGD process, the facilities (shaft, tunnels, underground drill rig, Phase B plant), the results of the three Phase A well pairs, and the drilling and design of the three Phase B well pairs which had not yet started-up. The second paper 1,2 reviewed the start-up and performance of the three Phase B well pairs and facilities which had produced 500,000 barrels of bitumen at that time, May, 1994. It also discussed the economics of a potential 30,000 bpd commercial SAGD recovery project. The current paper looks at the continuing performance of the Phase B wells and facilities which have produced over 2,400,000 barrels of bitumen; the design and April, 1996 start-up of two pairs of SAGD wells drilled from the surface (Phase D) which have produced over 170,000 barrels of bitumen; the design of a third surface well pair to be drilled in the spring of 1997 to test the methods of placing and operating a new well pair next to a depleted reservoir without adverse effects; the features of a produced water recycle plant scheduled for start-up in the fall of 1997; and concludes with a brief discussion of some commercial aspects related to the economics of the SAGD process at the UTF and the marketing of bitumen. The UTF Project is currently owned by the Alberta Oil Sands Technology and Research Authority (AOSTRA) and funded jointly by AOSTRA (25%) and nine Industry Participants (8 1/3% each) In addition to Gibson, the Industry Participants are: Amoco Canada Petroleum Company Limited., Chevron Canada Resources Limited, China National Petroleum Co. (Canada) Ltd., Imperial Oil Resources Limited, Japex Oil Sands Limited, Petro-Canada, Shell Canada Limited and Suncor Inc.

Abstract It is important to be able to predict the instantaneous forces and moments at the bit during drilling, but the rock/bit interaction process is not thoroughly understood. It is commonly accepted that the forces acting on a drag bit should be balanced to avoid excessive bit vibrations called whirling and uncontrolled well deviation resulting from non-symmetric side-cutting. However, the relationships between drilling forces and bit design features are uncertain because of the difficulty in obtaining reliable, quantitative measurements of cutting forces at the bit. A series of single cutter PDC (Polycrystalline Diamond Compact) experiments were conducted in the laboratory; in which three components of drilling force were measured. A rock was cut at the speed and load corresponding to the same parameters while PDC bit drilling. The variations in the value and direction of the resultant force were compared with the variations of the depth of cut and the simulated wellbore pressure. The relationship between the cross-section of cut rock and the measured forces at a PDC cutter were analyzed and used in the rock/bit modeling. A model for the resultant force at the bit was developed by integrating the effects of individual PDC cutters into a geometry of a given PDC bit design. The model describing kinematics of the PDC bit as well as the imbalance force resulting from the non-symmetric drilling forces distribution was developed. Then, simulations of a rock/bit interaction forces were run for the different depth of cut and a given rock described by the index of rock strength and coefficient of friction between the rock and PDC cutter. The obtained predictions of imbalance force and moments at the bit are presented for the conventional and center PDC bit designs. The results clearly indicate the differences between these two designs as well as the ability to predict the magnitude and orientation of the imbalance force generated while drilling with different PDC bit designs in different rock lithologies. Introduction The unexpected and excessive PDC cutter wear as well as the problems related to uncontrolled and/or unintended well deviations were recognized in the late 1980's. In 1989 a new theory of PDC bit failure was presented and called "bit whirl". It has been recognized that the bit stability is influenced mainly by lateral force causing a bit to walk around the wellbore. Since that time, research has focused almost entirely on modeling the whirling motion of the center of the bit and modeling the low static imbalance force at the bit. Some improvements have been obtained by developing techniques that stabilize the bit and generate the restoring force necessary to prevent the start of whirl. However, the mechanism of rock cutting is not still understood well enough to accurately predict the distribution of forces and moments at the bi-center PDC bit and the resulting bit behavior on instantaneous time scale while drilling. The main reasons are the following: 1) the directional tendencies of PDC bits have not been clearly defined to this point,

Abstract Hydraulic fracturing of low permeability reservoirs with multiple fractures is an effective stimulation treatment in the serial techniques of horizontal well production. The comprehensive mathematical model of predicting the production performance of a hydraulically fractured horizontal well with multiple fractures, combined the reservoir model and type of reservoir derive with the hydraulic fracture model is first established in this paper. The numerical models and the corresponding solution are first derived. Both fracture performance and reservoir performance in the transient producing period or pseudosteady producing period are taken into account. These models are applied to simulate the pressure performance of reservoir and multiple fractures in the horizontal well, to forecast the well production in the transient producing period and pseudosteady producing period. This paper investigates optimization of fracture numbers in the horizontal well, added the fracturing economic evaluation model to the comprehensive mathematical model. A case study is shown which demonstrates the method of forecasting production and optimizing fractures numbers. These models and the methodology can be employed in fracturing design of a horizontal well and evaluation of fracturing effectiveness. Introduction Hydraulic fracturing of horizontal wells, which enhances the oil reserves in the low permeability reservoir and keeps the oil wells high productivity is becoming an effective stimulation treatment in the serial techniques of horizontal well exploitation. Forecasting the production performance of a hydraulically fractured horizontal well plays an important role in the optimization design of hydraulically fracturing the horizontal well, furthermore it is the main basis of evaluating the effectiveness of post-fractured wells. Segment fracturing in the horizontal wells commonly induces multiple fractures which are oriented near the wellbore. Predicting the production performance of a fractured horizontal well with single fracture or several fractures can be used to determine the optimum fracture numbers and to improve the design of hydraulic fracturing treatment. This paper first presents the comprehensive mathematical model of predicting the production performance of a hydraulically fractured horizontal well with multiple fractures. The reservoir model, type of reservoir drive and hydraulic fracture model are included in the comprehensive model. Both pressure behaviors in the fractures or in the reservoir and well production in the transient producing period and pseudosteady producing period can be simulated. The fracturing economic evaluation model is introduced to investigate the optimization of numbers of fractures in fractured horizontal wells. A case study is presented which demonstrates the method of forecasting production and optimizing fracture numbers. These models and methodology can be employed in fracturing design of a horizontal well and evaluation of fracturing effectiveness. ESTABLISHMENT OF PHYSICAL MODEL Assumptions The object of this study is shown in figure 1 in which a fractured horizontal well with multiple fractures is located in the rectangular reservoir. The following assumptions are involved in the derivations of the mathematical model. The fractures are perpendicular to the wellhole and vertically penetrate the partial reservoir thickness. The horizontal well fully penetrates the reservoir or unfully penetrates the reservoir.

Abstract Gas leakage into and through the cemented annulus in oil and gas wells is a safety problem. The conditions for gas migration develop when the hydrostatic pressure of the hydrating cement slurry column slowly declines and finally falls below the pore pressure of a gas bearing formation. This pressure decline is mainly caused by chemical shrinkage of the cement. A low shrinkage will reduce the pressure decline and hence the risk of gas migration. A new and simple method for measurement of total chemical shrinkage at high temperatures has been developed. It has proved to be reliable and sensitive for monitoring the cement hydration process. The equipment was used to show that there is a marked difference in shrinkage behavior for the tested slurries up to 180 °C, probably due to a temperature effect on the cement hydration chemistry. The results confirmed the correlation between total shrinkage and cement content. Introduction Cement, or more precisely, cement slurries, are used in oil and gas wells for cementing the steel casing to the wellbore and thus sealing the rock formations from the well. Gas leakage into and through the cemented annulus is still a problem, in particular where shallow gas sands are penetrated and in deep gas wells, i.e. under high temperature and high pressure (HTHP) conditions. The leakage may manifest itself either as vertical communication between permeable gas reservoirs or migration all the way to the surface. Gas pressure in excess of the cement hydrostatic slurry pressure is the driving force behind gas migration. Reasons and mechanisms of gas migration are discussed by Levine et. al. l , Sabins et. al. 2 and Cheung and Beirute. 3 Annular gas flow may be initiated when the hydrostatic pressure of the cement slurry declines and falls below the pore pressure of a gas bearing formation due to the combined effect of shrinkage, fluid loss to the porous well bore and gel strength build up. Normally a slurry volume reduction would be compensated for by contraction and downward movement of fluids from above, thus maintaining its hydrostatic head. However, during the setting process the cement slurry develops a gel structure causing it to stick to the wall thus hindering compensation of the shrinkage. The second requirement for gas migration is that the cement must enable gas flow into the cement either by permeability, channels, microannuli or microfractures before the slurry has reached a sufficient strength. Thus, the gas migration phenomenon is thought to be initiated during the transition state, from being fluid to becoming hard, i.e. between initial and final set of the cement. A low shrinkage is preferable because the resulting hydrostatic pressure decline will be lower than for a slurry with high shrinkage, i.e. pressure equilibrium between gas and slurry column is reached at a later point of time. The chemical shrinkage may be divided into two parts; external shrinkage and total shrinkage. The external shrinkage expresses the bulk volume change of the slurry leading to a possible microannulus between the cement and the borehole wall.

Abstract Formation damage concerns in reservoirs with ultralow water saturations have been over dramatized; perhaps, because the mechanisms of permeability reduction as a result of extraneous fluid invasion are not well understood. It has been proposed that some gas reservoirs contain less than reducible water, S wrl and as such, have additional pore volume which contributes to hydrocarbon permeability. Consequently, introduction of fluids during drilling, completion and workovers could result in more permeability loss in these reservoirs, than in reservoirs which contain water saturations controlled by capillary pressure. This paper demonstrates, with laboratory data and with Poiseuille's theory, that for water-wet reservoirs (which most gas reservoirs are, since gas is strongly non wetting) areas of porosity where bound water exists, contribute little to the overall permeability. Several permeability measurements performed on clastic, limestone and dolomite core samples with and without connate water saturation demonstrate that minimal permeability reduction occurs due to irreducible water saturation. Even in extremely low permeability cores less than 0.5 md, the effect of irreducible water saturation on gas permeability was only a 20 percent reduction. These results suggest that permeability damage is only slightly worse in desiccated gas reservoirs than in conventional gas reservoirs. Furthermore, permeability impairment as a result of fluid invasion is more a function of effects on macroporosity than microporosity. Introduction With the increased activity in natural gas exploitation in Canada, much attention has been drawn to the potential for formation damage as a result of introduction of drilling and completion fluids, particularly in low permeability gas reservoirs. A perception exists that damage may be more severe in reservoirs which are initially at ultra-low water saturations, i.e. lower than what might be predicted from capillary pressure measurements. This thinking differs from the general consensus that microporosity, which is the major portion of pore volume controlling water saturation in a water-wet reservoir, contributes little to permeability. This paper reviews various literature on the relationship of pore size and water saturation with respect to contribution to permeability. Laboratory permeability measurements on cores from four formations are presented and compared to other published data, to demonstrate the effect of water saturation on effective permeability, and how it relates to capillary pressure and pore throat size. Finally, a technique will be presented, based on Poiseuille's theory, on how to calculate the contribution to permeability as a function of pore throat size using air/mercury capillary pressure data. LITERATURE REVIEW Thomeer 1 and Swanson 2 developed empirical techniques for predicting absolute permeability from capillary pressure data. They recognized the insignificant contribution to permeability of smaller pores compared to the contribution of larger pores. Swanson's method of characterizing capillary pressure curves uses the inflection point (point A in Figure A) on the lower portion of the capillary pressure curve to predict permeability. He argues that this inflection point represents the maximum product of pore throat size times effective flow area. The value of this maximum, which is inversely proportional to the distance of the inflection point from the lower left-hand corner of the axes, is proportional to permeability.

Abstract There currently exists a large supply of heavy crude oils which are relatively uneconomical to produce. However, there are processes available which can be used in a downhole environment to upgrade them, resulting in significantly less sulfur and lowered densities and viscosities. A process which is especially favorable for downhole implementation is the use of in situ combustion to generate reactive upgrading gases, such as CO 2 and to drive oil over a near-wellbore heated bed of catalyst. Two laboratory combustion tube runs were completed to test this concept. These differed from normal combustion experiments in that they employed a heated processing zone over which combustion gases and fluids passed prior to production. The first run used sand in the processing zone, and the second a bed of catalyst. The Middle Eastern heavy crude oil used was amenable to combustion, and the presence of a heated production-end processing zone did not affect the combustion performance. Passing oil and combustion gases over the catalyst prior to production resulted in substantial upgrading of the produced oil, including a 50% level of hydrodensulfurization and substantial decreases in oil gravity and viscosity. The catalyst efficiently converted CO 2 generated at the combustion front, to H 2 , which then reacted with the oil to effect upgrading. The catalyst-bearing zone appeared to have a very low residual water saturation and was effectively oil wet, thus assuring that good oil-catalyst contacting occurred. However, it was found that the presence of a large amount of coke on the catalyst may indicate the need for periodic regeneration. INTRODUCTION Although there exists a large supply of heavy crude oil throughout the world, most of these reserves tie untapped for various reasons, chief among them being the poor economics of recovering heavy oils. The authors have recently described processes that could be used for significant downhole (in situ) upgrading of heavy crude oils 1,2 , despite previous reports which found that in situ processing has limited potential 3 . In situ processing has several advantages over conventional surface upgrading technologies. Because in situ upgrading can be implemented on a well-by-well basis, there is no needed for large capital-intensive projects. Rather, the size of an in situ project, for a particular field, can be tailored to available production rates; thus, upgrading is practical even for those fields deemed too small to provide sufficient production for conventional processing. Additional advantages for in situ upgrading include the production of a more desirable and valuable product, increased ease in shipping and pipelining, and less-demanding downstream processing. The requirements for in situ upgrading include: provision for a downhole bed of catalyst, achieving appropriate reaction temperatures and pressures at the catalyst bed, and mobilization of oil and co-reactants over the catalyst. Although the technologies to accomplish each of these tasks are fairly well known, their combination into a unified process has yet to be demonstrated. A bed of catalyst can be placed by conventional gravel pack or proppant injection methods 4,5 .

Abstract Forecasting volumetric sweep efficiency and oil recovery of a miscible flood is difficult, yet reliable production forecasts are required for economic analysis. Conventional decline curve analysis cannot be applied until well after the miscible flood is underway, and may be inapplicable if oil production rates are constant or increasing. Numerical simulation can usually give reliable estimates of oil recovery but only after a time consuming history match. However, simulation can be extremely time consuming. Computer resources and man power constraints can often limit the areal extent of a model, and therefore limit the model's applicability for full field forecasts. In this study, simple methods based on waterflood surveillance techniques were developed for estimating miscible flood volumetric sweep efficiency. These methods can be used to predict ultimate recovery and volumetric sweep for horizontal miscible floods in either strongly gravity dominated system, heterogeneous systems or viscous fingering dominated systems. Miscible flood simulation studies and results from actual field projects show that a plot of gas-oil ratio (GOR) correlates well with cumulative incremental oil production. Such a plot can be used to estimate miscible flood incremental recovery. If the log GOR vs. cumulative oil is a straight line, this implies that the late oil rate decline will be either harmonic or hyperbolic depending upon total fluid production rate. These surveillance techniques can identify areas in which volumetric sweep and oil recovery is performing below expectations. These techniques allow an operator to continuously monitor performance and to make timely operational changes to maximize oil recovery. Introduction It is critical that a development team has an excellent knowledge of reserves remaining in a reservoir to plan optimum depletion strategies. Unfortunately the reservoir engineer has a difficult decision on predicting reserves they can choose from decline analysis or simulation. Determining incremental oil in a tertiary miscible flood by decline analysis is especially difficult because: Often dally fluctuations in oil rate may be greater than the incremental oil rates attributed to miscible flooding Infill drilling and well work overs are occurring simultaneously as miscible floods start up so it is difficult to attribute oil production to tertiary miscible response Initial overall oil rates are constant or increasing These factors mean that conventional decline analysis cannot be applied until well after the miscible flood is underway. For a more "accurate" answer, the reservoir engineer can use numerical simulation but this approach requires detailed reservoir knowledge, usually requires fine detailed grids and is extensive and time consuming. Therefore simulation is limited to only portions of the reservoir. On the other hand., large capital intensive decisions need to be made on an ongoing basis. It is therefore critical to determine what the incremental recovery and volumetric sweep are in a timely fashion. Many surveillance techniques that have been developed for waterfloods and gas floods are applicable to miscible floods, with slight modifications. In this paper techniques are derived for gas flood and modified for miscible flood. The techniques are validated using numerical simulation.

Abstract Aqueous and hydrocarbon phase traps can occur in porous media when water- or oil-based fluids come into contact with a formation which exhibits a "subirreducible" initial liquid saturation of the phase of interest. This commonly occurs with water-based fluids in many low permeability desiccated gas bearing formations and in depleted conditions in rich gas retrograde condensate reservoirs. This paper documents how phase traps are induced by direct displacement, counter current imbibition or depletion effects, and presents techniques for diagnosing whether a reservoir is a candidate for an aqueous phase trapping problem. Techniques to minimize problems with aqueous and hydrocarbon phase trapping are reviewed, followed by discussion of methods to reduce or remove the effect of existing phase traps, such as increased drawdown, alteration of 1FT, alteration of pore geometry or direct removal methods. A brief discussion of laboratory techniques used to screen the optimum process for selection are also presented.. Introduction The phenomena of permanent entrainment of extraneous or insitu generated aqueous or hydrocarbon based liquids in porous media has been documented in the literature as a mechanism for significant permeability impairment in low permeability intercrystalline sandstone and carbonate formations 1–5 . Phase traps normally occur when a water or hydrocarbon based fluid is either forced or imbibed into porous media with a subirreducible water or hydrocarbon saturation (ie. at a saturation less than the irreducible liquid saturation given the geometry, wettability and capillary mechanics of the system under consideration). Subirreducible hydrocarbon saturations are common in rich gas retrograde systems existing in a sub-dew point condition, or in mature gas fields which may have migrated into previously oil saturated strata. Subirreducible water saturations in low permeability gas reservoirs are also quite common. The mechanism for the establishment of a sub-irreducible water saturation in a low permeability gas-bearing reservoir is the subject of some controversy. The dominant mechanism is thought to be desiccation motivated by a large regional migration of gas under conditions of increasing temperature and pressure through a given reservoir area over a long period of geological time. The basic mechanism of a phase trap is created by the relative permeability effect associated with an increase in the immobile water or hydrocarbon saturation. This phenomena is illustrated on a pore scale in Figure I and from a mechanistic point of view as Figure 2. The severity of the phase trap is strongly influenced by: The magnitude of the difference between the "initial" and final trapped "irreducible" liquid saturation which exists in the porous media. The greater this difference, the larger the adverse relative permeability effect and the greater the potential reduction in permeability. The configuration of the gas or oil phase relativ permeability curves at low liquid saturation levels. The more adverse the configuration of these curves (ie. the more convex the relative permeability curve), the more significant the reduction in permeability for a given increase in trapped liquid saturation. The depth of invasion of the trapped phase. The greate the volume of fluid lost and deeper the invasion, the more difficult and slow the mobilization of this fluid becomes.

Abstract High acid gas content streams, consisting primarily of carbon dioxide, hydrogen sulphide or a combination of both are commonly generated as a by-product of the sweetening process used to bring many produced gases and solution gases to pipeline specifications for sales and transport. Typically, sour gas has been extractedfrom acid gases through the use of Claus or other types of elemental sulphur reduction processes, the sulphur sold or stockpiled, and the residual carbon dioxide vented to atmosphere. With depressed prices for the commercial sale of sulphur and environmental concerns with the emission of large volumes of greenhouse gases, considerable interest has been extant in the industry into the feasibility of the reinjection of acid gas from sweetening processes, either back into the original producing formation, or into selected disposal zones which may consist of aquifers or depleted previously produced oil or gas zones. A major concern with the re-injection process is the potential for formation damage and reduced injectivity in the vicinity of the acid gas injection disposal wells, as well as reservoir screening criteria with respect to suitable gas containment concerning the subsequent migration of injected acid gases. This paper discusses screening criteria for reservoir selection for zones suitable for acid/sour gas re-injection Or disposal, and highlights potential areas of concern for reduced injectivity. Such phenomena include acid gas induced formation dissolution, fines migration, precipitation and scale potential, oil or condensate banking and plugging, asphaltene and elemental sulphur deposition, hydrate plugging and multiphase flow phenomena associated with acid gas compression phenomena. Variations on acid gas injection schemes, such as concurrent contacting with produced water at elevated pressures and subsequent disposal of the Sour water, will also be discussed andpotential damage concerns highlighted A variety of screening and laboratory tests and results will be presented which illustrate the various damage mechanisms outlined and provide a specific set of design criteria to evaluate the feasibility of an acid gas injection/disposal operation. Introduction Acid gases (gases which contain carbon dioxide (CO 2 ) and hydrogen sulphide (H 2 S)) are produced from many formations as either free gas or liberated solution gas from sour oils. These gases must be "sweetened" to selectively remove the acid gas components before the gas can be transported and sold for commercial use. A variety of sweetening processes are used to remove acid gas components (amine extraction being the most common). The sweetening process results in the production of acid gas-free "sales" gas, and a rich waste gas stream consisting of virtually pure CO 2 and H 2 S (commonly referred to as concentrated acid gas). In the past, a variety of techniques have been used to handle acid gas streams, most of them primarily concerned with the reduction of the extremely toxic hydrogen sulphide to an inert/non-toxic reaction product. The most common technique is the Claus reaction process where the H 2 S gas in the acid gas stream is catalytically converted to elemental sulphur. This process was an economic one in the past, particularly when sulphur prices were in excess of $ 150/tonne. Many operators deliberately attempted to exploit reservoirs containing high concentrations of H 2 S with sulphur recovery, rather than the value of the sweet sales gas, being the primary motivating factor.

Abstract As a vertical miscible flood matures, oil production becomes dominated by the coning of gas / solvent, and as a result, oil rates drop rapidly. Application of the oil reinjection process arrests the rapid decline by increasing the oil rates and also by increasing the reserves. Testing of this concept was initiated by Imperial Oil in a 1993 – 1994 single well pilot!. Since that time, based on the encouraging results obtained from the pilot, plans are underway to expand the application of oil re-injection to all seven Imperial Oil operated Cynthia Nisku miscibly flooded pools. Presented in this paper are examples of two oil re-injection projects that were initiated in the Cynthia Nisku "G" and "L" pools. Both projects have been in operation for approximately one and a half years. Their performance to date shows that increased oil rates can be sustained and one of the pools has demonstrated a change in pool decline thereby indicating that there are incremental reserves associated with the oil re-injection process. The two pools represent contrasts in oil re-injection response. Monitoring and diagnostics were developed and applied to quantify the oil re-injection process dynamics in the near wellbore region and to test wellbore management techniques. The knowledge gained from these two projects has provided valuable insights for setting expectations and providing a framework for optimizing performance. Introduction In a maturing vertical flood, once gas / solvent enters the near wellbore region, the high mobility of the solvent causes its production to increase while oil production decreases. Figure 1 shows the typical behavior for a well in a maturingvertical flood. Between the months of July 1995 and April 1995, the gas-oil ratio for this well increased from 180 sm 3 /m 3 to 325 sm 3 /m 3 . This represents a gas-oil ratio increase of approximately one hundred percent on an annualized basis. The increase in the gas-oil ratio was accompanied by a rapid decline in the oil rate. The oil rate declined from 130 m 3 /day to 95 m 3 /day representing a thirty-two percent decline on an annualized basis. The conventional way to combat the increasing gas-oil ratio in a well that is completed at the bottom of the reservoir is to lower the choke size. However, this only provides temporary relief as gas-oil ratios will continue to increase while oil rates continue to decline thereby resulting in declining revenues. OIL RE-INJECTION PROCESS AND OBJECTIVES The initial expectations for the oil re-injection process when the technology plan was being conceived were as follows: Oil production decline would be arrested and rates would be maintained for at least one year before resuming the decline. Gas-oil ratio's would be maintained flat over the entire operating period. Oil reserves would be increased. The primary mechanism involved in this technology is the reduction in the mobility of the solvent in the near wellbore region brought about by the injection of oil into a solvent cone and/or near wellbore channel.

Abstract A major challenge in the reclamation and restoration of oil sands processing wastes is the reestablishment of self-sustaining ecosystems. The primary task is the development of a technology to create stable aggregates to a soil-like profile capable of supporting a stable vegetative community. It was considered that aggregates (stable agglomerates of mineral particles and organic matter between 0.1-10 mm diameter) can enhance the physical environment of the resulting soil profile, help with the establishment of a plant and soil microbial community, and facilitate the development of natural soil structure. We developed a procedure to artificially create aggregates using oil sands mining wastes, namely tailings sand, mature fine tails, and composite tails. The clay and water contents played critical roles in the success of the aggregation procedure. The resulting aggregates were relatively stable and they had a loam texture which would be suitable for use as a medium for plant growth Introduction Surface mining and water-based extraction of the oil sands in northeastern Alberta have generated large volumes of tailings sand and fine tails. Tailings slurry from the extraction plants contains significant quantities of water, residual bitumen, coarse-grained and fine grained materials that are pumped into large settling ponds. The coarse-grained "tailings sand" quickly settles out to form the dykes and beaches. Much of the fine grained materials (silts and clays) and residual bitumen that sink in the pond form an accreting layer which consolidates very slowly. When consolidation reaches 30% solid by weight (several years), the resulting deposit is known as "mature fine tails." Currently some 350 million cubic meters of fine tails have been produced and are being stored in large tailings ponds. It is possible that a billion cubic meters of mature fine tails will have been produced and stored in the ponds by the year 2025. Recent research to accelerate the consolidation process of mature fine tails has resulted in the development of a treatment method which involves the addition of gypsum (calcium sulfate) to a fines-enriched tailings slurry. The calcium in the gypsum replaces the sodium in the clays of the mature fine tails, resulting in the very rapid release of water (approximately 25% of the volume of the mature fine tails within a few days). The consolidated dense materials which now have a solid content of approximately 80% by weight is termed "composite tails". One of the major challenges in the reclamation and restoration of these waste materials is the establishment of self-sustaining ecosystems. The primary task is to develop, using these waste materials, a technology to artificially create a soil-like profile capable of supporting a stable plant community. The primary characteristics for such a soil profile are: it must be able to supply sufficient soil water and nutrients within the root zone for plant growth; it must provide a physically stable medium for plant growth and be resistant to soil erosion; and it must be a chemically and biologically active medium to buffer the effects of changing environment on plants and soil micro-organisms (l) .

Abstract A heat transfer technique for the detection of the onset of asphaltene precipitation is presented and its versatility demonstrated. The technique is able to evaluate the effectiveness of asphaltene precipitation inhibitors, and solvents used to resuspend a deposit. It can also be used to study the reversibility of asphaltene precipitation. A number of chemical species were tested for their ability to delay the onset a/precipitation. The nonionic surfactant nonyl phenol was the most effective chemical tested. Toluene and xylenes were shown to resuspend an-heptane precipitated deposit, and it was found that xylenes were, in general, more effective. Temperature traces indicate that the redissolution of precipitated asphaltenes upon n-heptane removal is reversible but incomplete. It is possible that the dissolution process may have proceeded further had longer dissolution times been allowed. Introduction Asphaltene flocculation and precipitation remains a problem to petroleum production, refining, and upgrading operations. During production, asphaltenes may precipitate in the reservoir, well, or separation equipment leading to reduced production. In refining and upgrading, asphaltene flocculation and precipitation is acknowledged as the first step in the formation of coke, an unwanted product. The asphaltene fraction is defined as the material of a petroleum sample that is soluble in toluene and insoluble in the solvents n-pentane or n-heptane at a dilution of 40 millilitre solvent per millilitre petroleum. Being a solubility class, the asphaltenes compose a large number of different molecules. Which are usually very difficult to separate. The methods used to isolate asphaltenes, and the influence of various parameters such as solvent type and contact time have been presented by Speight et al. 1 . Asphaltenes are the highest molecular weight species, contain the largest weight percent of the undesirable heteroatoms nitrogen, sulphur, and oxygen, and are the most aromatic fraction of a petroleum (Speighr 2 ). When considering the stability of petroleum, it is known that a balance between the three pseudo-components: oil, resins, and asphaltenes is required. The resins fraction is responsible for keeping the asphaltenes in colloidal suspension, as was emphasized by Pfeiffer and Saal 3 . The resins peptize the asphaltenes by acting as a transition between the aromatic polar asphaltenes and the non-polar aliphatic oils, thus preventing asphaltene flocculation and subsequent precipitation. The importance of the resins has been further emphasized by others, such as Nellensteyn 4 , Swanson 5 , Koots and Speight 6 , and Andersen 7 . In refining and upgrading processes, such as visbreaking, coking, and hydrocracking, where temperatures are typically in the order of 380 °C to 500 °C, reactions take place that cause the composition of the feed to change. In many of these processes, the net effect is that resins are depleted and the amount of asphaltenes increases (Lepage et al 8 , and Storm et al 9 , Wiehe 10 ). To prevent coking in these processes, which is a result of asphaltene condensation reactions, asphaltene flocculation and precipitation must be prevented. Feeds to these processes typically have 20 or more weight percent asphaltenes.

Abstract The Mannville Q Pool is one of a group of Glauconitic oil and gas pools located in the Gadsby area of east-central Alberta. This paper outlines the recent devewpment of this pool and presents the advantages ofutilizing a synergistic approach involving detailed geological, geophysical and reservoir engineering analyses. Particular emphasis is given to the practical application and implementation of the recommendations formulated by the development team. Streamlined project management allowed planning and construction of field facilitie,. drilling of a horizontal re-entry well and testing of an enhanced recovery scheme within a 4-month period. Field results before and after this recent development are also discussed. INTRODUCTION The Gadsby Mannville QPool (the "Pool") is located in east-centra1 Alberta in Section 6, Township 38, Range 18 west of the Fourth Meridian (Figure 1). Light gravity oil of 31 °API is being produced from the Glauconitic sandstone reservoir. Oil production commenced in 1991. Since the pool is located under Lonepine Lake in the Gadsby area, all wells were drilled directionally into the formation. In September 1995, before commencement of additional pool development, only four of the eight wells were producing due to a gas-oil ratio (GOR) penalty which restricted oil production from the Pool. Two wells (08–01 and 09–01) located in Section 1 of Township 38, Range 19 west of the Fourth Meridian were producing at much lower rates of I to 2 m 3 of oil per day. Recent pressure surveys suggest that they are in a separate reservoir, in concurrence with additional geological and geophysical analyses. In the main pool, located in Section 6, only two wells (02–06 and 06–06) were producing at a combined oil rate of about 24 m 3 per day with a GOR of about 250 m 3 /m 3 . However, with an assigned base GOR of 100 m 3 /m 3 , these wells could only be produced for two weeks per month to avoid overproduction as a result of the GOR penalty. The total penalized oil production from the Pool in September averaged 16 m 3 per day (100 BOPD). Gas was not conserved at the time. In September 1995, Best Pacific Resources Ltd. became the operator of the Pool as well as several gas wells producing from separate Glauconitic pools in the Gadsby area. A detailed geological, geophysical and reservoir engineering evaluation was initiated to investigate the potential of creating additional value through further development of the field by horizontal drilling and pressure maintenance. Based on a detailed geological study, three dimensional (3-D) seismic and reservoir simulation, a horizontal re-entry candidate was chosen at 05–06–38–18 W4M. The horizontal well was drilled in November 1995 and placed on production in December 1995. Initial production results from the horizontal re-entry well were significant as it flowed at a sustained rate of 90 m 3 per day with a 2% watercut in a two-day flow test. In January 1996, it was equipped to pump and tied in to the recently constructed central battery.

Abstract Given today's business environment, investments in technology must deliver value which significantly exceeds the cost of developing and applying the technology. Quantification of this value is a significant challenge. Quantification of the value of technology enables prioritization of diverse technical efforts when coupled with strategic considerations related to a specific asset base. This prioritization can be used to maximize the impact of investment as well as helping to balance research and development against application of existing technology. Upstream technology investment at Mobil has been reduced significantly in the past five years, in part because of our inability to quantify the value of technology. Decisions to resize technology efforts are driven by cost rather than value-to-cost considerations. Recurrent cycles of reduced investment cannot comprehend the resulting loss of value. A quantitative value-to-cost analysis was performed for the upstream technology portfolio at Mobil for the period 1993–1998. The overall cost of developing and delivering various technologies was quantified as was the net present value from technologies applied to thirty major assets. The value captured was classified into four general categories: reduced capital costs, reduced operating costs, increased hydrocarbon production, and increased proved reserves. This paper details the methods used to quantity the value to- cost of upstream technologies and the results of the thirty asset analysis. Samples of the value of technology to specific assets will be presented. Finally, a method of incorporating strategic considerations and business alignment to set overall program priorities will be discussed. Why Quantify Technology Value The pressure to continually operate more efficiently has forced petroleum companies to examine every piece of their business for potential improvement. The need to reduce costs is driven by business pressures from competitors who are reducing their costs and by the need to maintain market share within an environment of no potential for real price growth in the foreseeable future. The industry as a whole has been extremely successful at improving efficiency - producing costs at Mobil have been reduced steadily since 1990 even though producing operations have become more complex and locations have become more remote. All of the major public oil companies, and many state-run companies, maintain a technology organization that provides technical service support to their operating divisions and performs some level of research and development. The cost of providing this technology support is highly scrutinized in the search for efficiency improvement. Within Mobil technology center spending has been reduced significantly from 1992 to 1995. R&D spending bore a disproportionate share of the reductions, indicating not only a downward trend in technology investment, but also a shift in emphasis away from R&D and toward technical service. The environment in which these technology organizations function is rapidly changing and is in part responsible for the reduced spending. Alliances with universities, government laboratories and partner companies are strategic endeavors to provide technology at lower costs. Outsourcing of non-core technology to low cost, specialty providers is also very efficient since companies are no longer willing to invest in every area of technology and since the quality of outside technology continues to improve.

Abstract This paper describes the field implementation of a novel gas lifting strategy used to enhance production from water flooded reservoirs. A patented "one level" gas injector, initially designed and tested for stripper well applications, was redesigned and successfully employed for a water flooded field. One of the strengths of the novel gas injector is its simplicity and robustness. More importantly, the application of this technology resulted in a productivity increase of 40%, as compared to commonly used rod pumps and maintenance costs were considerably reduced. The economic and theoretical criteria used to select candidate wells for the novel gas lift, to design surface equipment, and to optimize gas injection (including the start-up procedure) are discussed in some detail. A comparison is made between the theoretical gas lift performance curve as based on Taitel-Dukler two-phase flow pattern identification, and field results. The limiting criteria for gas lifting strategy, as based on theoretical and practical considerations, demonstrate the effectiveness of this novel technique, and indicate the range of conditions over which it can be applied successfully. INTRODUCTION In a previous laboratory and theoretical study a novel gas lifting injector and strategy for increasing productivity of wells with limited reservoir pressure and high GOR was discussed. Field implementation of the one-level gas injector tool requires in-depth assessment of gas-liquid flow in the producing tubing and in the injector. 1his assessment demonstrated the feasibility and economics of the system. To find acceptable candidate wells and to decide upon the depth of the injector and compressor characteristics, design criteria developed during a previous laboratory-theoretical study were used. The design criteria included: production well history and economics, static fluid level (where available, bottom hole flow pressure or the inflow performance relationship-IPR-), depth of the injector and submergence, tubing-casing geometry and two-phase flow pattern and pressure drop (vertical lift performance -VLP-). The submergence, defined as the ratio of the distance between the static fluid level and the injector to the distance between the injector and surface separation, was found to be one of the most important criteria for obtaining a quick estimate of the gas lifting productivity and therefore the potential success of the application'. Overlooking the "submergence criteria" during preliminary testing of the novel gas lifting tool and strategy lead to unsatisfactory results as described below: 1. In the Gooseberry Lake field (completion at approximate 923 mKB and fluid level at 540 mKB) a submergence of only 0.35 was achieved by positioning the injector at 835 mKB; for this particular situation, the static fluid level was too low for implementing a risk-free, efficient gas lifting strategy. Low fluid level and production history indicated that the well should not even be considered for gas lifting. Errors in the initial measurements of the static fluid level (initiallyestimatedat316 mKB instead of 540mKB) as well as non-technical considerations were used for the selection. The futile effort to gas lift the "Gooseberry Lake" well demonstrated that previous laboratory and theoretical conclusions suggesting a minimum of 0.5 submergence as a primary (but not unique) well selection criteria should be respected for selection of potential site selection.

Abstract The performance of a horizontal well in the presence of a growing cone before breakthrough is studied. Examining the flow mechanism in rese11loirs with bottom water or gas cap, we consider the interface as a no-flow moving boundary before breakthrough. The paper presents a dimensionless variable, Dimensionless Density, as a function of reservoir thickness, anisotropy coefficient, difference of the fluid densities, production rate and viscosity. This study indicates the existence of a Critical Dimensionless Density (CDD), above which water or gas cone is stable. The results of this study show that the higher the viscosity, the higher is the con~ height and consequently the smaller is the breakthrough time. Thus processes such as steam stimulation can postpone the breakthrough time. The results show that, before breakthrough, a potential solution of a no-flow boundary at the initial interface is a better approximation with respect to those with a constant potential boundary conditions. The shape of the interface during production is developed. INTRODUCTION The performance of a horizontal well in reservoirs with bottom water or gas cap has been studied through the assumption of constant potential (pressure) at the initial interface, (Refs. 1 and 2). However, before breakthrough, there is another no-flow boundary between the two fluids which can move toward the wellbore or be stationary (at steady state). To the best of the authors knowledge, this intermediate no-flow boundary has not been considered in the horizontal well performance elsewhere in the literature. However. Ref. 3 considering the interface as a no-flow moving boundary, presented the performance of a vertical well in the presence of a growing cone. To calculate the interface advance based on the equations derived in this paper. One has to have the potential values on the interface and outer boundaries. On the other hand the potential distribution inside the reservoir depends on wellbore configuration. Therefore to calculate the potential distribution inside the reservoir due to a horizontal well with arbitrary geometry, Discrete Flux Element Method (DFE) , presented by Azar-Nejad, Tortike and Farouq Ali 4–6 has been used. Applying a transformation rule presented in Refs. 3 and 7. The deformed interface is shifted to its initial position. In a reservoir with a horizontal well this implies that the wellbore geometry be transformed accordingly. The resulting wellbore with irregular geometry, in the transformed space, can only be modeled by DFE Method. PREVIOUS STUDIES Coning is a term where has been used to describe the WOC deformation. Numerous papers have been published with the purpose of calculating the critical production rate (Refs. 7 through 16) and the time of the water breakthrough (Refs. 17 through 19). Muskat and Wykoff 8 presenting the static equilibrium, developed a solution for the critical production rate for a vertical well under steady state conditions. As the WOC was a no-flow boundary with unknown and irregular configuration and location, Muskat et al 8 , assumed the original WOC to be a no-flow boundary. However they postulated that if one could consider the real WOC as a no flow boundary, the critical production rate would have been lower. Therefore, the solution for critical production rate given by Muskat et al 8 is an approximation and an upper limit on the exact solutions.

Abstract Correct choice of perforation orientation in wells can either reduce risk of sanding initiation, or increase the possibility of massive sand production. This article presents a simplified approach to this evaluation procedure, based on stresses induced around perforation cavities in a cased wellbore. The effect of perforation orientation is shown to be a first-order component; therefore, along with other factors such as draw-down rate and charge size and density, such a procedure should be incorporated into sanding evaluation. INTRODUCTION Solids production is a negative aspect of high-rate oil or gas production from weak reservoir rocks. By contrast, massive solids production in viscous heavy oils found in unconsolidated strata is highly beneficial in increasing production rates. In the former case, well completion strategies and production practices are implemented to reduce the incidence of deleterious solids influx: the goal is exclusion while maintaining acceptable production. In the latter case, practices are implemented to keep sand flowing into the hole to maintain the enhanced production (often by a factor of 10 or more): the goal is maximum production, along with sand management Aspects of optimization and risk enter into both cases. To achieve an economic completions strategy compatible with production rates, one must understand the mechanisms involved, carry out analyses which capture the key factors which contribute to solids and fluids production, and come up with acceptable engineering solutions. Smith (1988) discussed possible mechanisms involved in massive solids production, focusing on the fluid flow aspects. Dusseault and Santarelli (1989) also addressed the mechanisms involved in massive continuous solids production, focusing on geomechanical aspects. This work has recently been approximately quantified, based on the concept ()f stress- and flow-induced liquefaction of the unconsolidated sand fabric (Geilikman et al., 1994; 1995). To confirm these models and ultimately develop a practical tool for sand management, field data are considered to be vital. Most published articles involve case history documentation and ameliorative procedures, usually for sand exclusion, often combined with a method of analysis (e.g.: Durrett et al., 1977; Morita et al., 1987; Santarelli et al., 1991; Morita et al., 1991; Weingarten and Perkins, 1992; Moricca et al., 1994b; Ramos et al., 1994). Limited experimental data are also available for all types of solids production in order to quantitively define the sand production processes (Tronvoll et al., 1992; Kocijrnan et al., 1992; Tronvoll and Halleck, 1994; Yim et al., 1994). Yet other studies involve only development of methods of analysis to model sand production initiation. Erath and Risnes (1981) proposed a quantitative isothermal criterion for solids production initiation using a Mohr-Coulomb yield criterion and a spherical cavity in an isotropic stress field. Similar approaches for cylindrical cavities, intended for borehole stability (Wang and Dusseanlt, 1991), apply the analysis for unconsolidated sandstones into elastoplastic cases and non-isothermal conditions characteristic of heavy oil reservoirs (Wang and Dusseault, 1995; Wang, 1995). Weingarten and Perkins (1995) extend similar approaches into gas production cases. All these studies, however, are strictly limited to a 2-D vertical well case subjected to a uniformly distributed stress.

Abstract Formation damage caused by fracturing fluid invasion along the fracture face has long been a concern in the petroleum industry. The results of a study on the effect of fracturing fluid cleanup and fracture face damage Oil gas production are presented. A numerical reservoir simulator is used to simulate (J) fracturing fluid invasion, (2) filtrate cleanup, and (3) gas production after the fracturing treatment. The reservoir properties used in the model are obtained from an example well in the Cadomin formation from the deep basin area of northwestern Alberta. The rock/fluid interaction properties of this apparently "water-sensitive" formation are determined in the laboratory. Results of numerical simulation are used to match the actual pressure buildup test results. The cleanup process of the invaded fluid is demonstrated, as well as how gas production is affected by the permeability damage at the fracture face. An algorithm combining the analytical and numerical methods to determine the fracturing fluid leakoff distribution profile is also summarized. Introduction It is well known in the petroleum industry that formation damage, caused by the invasion of drilling and completion fluids in an unfractured well, can significantly impair theflow of reservoir fluids. When fluid flow from the reservoir into the wellbore is radial, the majority of the pressure losses ccur near the wellbore. Any permeability damage in this region will further increase the pressure drop and greatly reduce the flow rate of the reservoir fluids. During hydraulic fracture treatments, fracturing fluid or filtrate will leak into the formation along faces of the fracture. This invasion of fluid can reduce the effective permeability to reservoir fluids and impair the flow of reservoir fluids. However, the exposed area of the formation face in a fractured well is much greater than that of an unfractured well. With properly designed fracture conductivity, the pressure loss along the fracture length is negligible. As a result of the large area exposed the flow velocity from the reservoir, through the fracture face, is small. The consequence is a significantly reduced pressure loss around the fracture, compared to that around the wellbore in an unfractured well. Consequently, permeability reduction at the fracture face has a much lesser impact on reservoir fluid production than the permeability reduction around an unfractured wellbore. The types of fracture face damage may be classified In two categories: Absolute permeability damage is the reduction in the absolute permeability of the rock within the invaded zone. This may result from polymer invasion, clayswelling or migration, scale or paraffin precipitation, stabilized emulsions, and other similar physical porosity modifications. In this discussion, it is assumed the permanent damage does not change during the cleanup and production periods. Relative permeability damage is the reduction in the effective permeability to reservoir oil and gas caused by the changes in fluid saturation and rock wettability. This in turn causes the changes in relative permeability and capillary pressure. This type of damage changes as fluid saturation changes. In 1975, Holditch 1 published a classic paper on the factors affecting water blocking and gas flow from hydraulically fractured gas wells. He demonstrated the combined effects of permanent formation permeability damage and relative permeability damage on gas production in low-permeability gas formations. He concluded the damaged zone permeability must be reduced by several orders of magnitude and the capillary pressure altered, before a se

Abstract Although not routinely cored, horizontal wells are usually drilled ill developed fields where good core coverage exists. This provides an opportunity to reevaluate pre-existing cores for detailed analysis. Additionally, formations can be pilot-hole drilled and cored, prior to going horizontal. For non-coredreservoir sections, drill cuttings can be valuable in formations evaluation. Areas that should be assessed before horizontal drilling include, reservoir description, wellbore stability, and formation damage potential. Reservoir description, including heterogeneity definition, is more difficult in horizontal wells when they are not cored or logged. Current evaluation methods include thin-section petrology and mercuryinjection on drill cuttings from the horizontal well. Where difficulty is encountered in identifying fluid contacts, thermal extraction chromatography (TEC) can be performed. Petrology, capillary pressure, and TEC analyses, require accurate sample and cuttings collection at the well surface. Automated cuttings samplers provide a superior collection method overmanual methods. Though horizontal wells are not usually logged, gamma ray devices are frequently run in conjunction with MWD tools. Transforms can be developed between the gamma response and permeability from existing offset cores. High resolutionpermeability logging devices can be utilized, which provide continu.ous, log-profile data for more accurate permeability models. Wellbore stability analysis is performed by either dynamic or static methods. These tests provide mechanical properties for describing the rock "failureenvelope", and predicting safe operating conditions during drilling and production. Formation damage testing is typically performed on existing cores from offsets, and involves petrology and ynamic /leakoff/regain permeability testing. A key use of damage is mud solids invasion, which can be assessed and optimized using mercury injection oncore or cuttings, together with panicle size analysis of drilling mud solids. Introduction The applications for horizontal well technology are numerous including: intersecting (or avoiding) natural fractures, mitigating coning, accessing low permeability reservoirs, reducing production related problems such as scale, sanding and fines migration, improved EOR (thermal and miscible), accessing offshore and environmentally sensitive locations, and gas storage. With all these applications, there are common objectives: accelerated production, increased recovery, and improved cashflow. 1 Given the rapid growth of horizontal drilling, itappears that industry is achieving these objectives, despite recent statistics which indicate that 35 percent of horizontal wells are still uneconomic. . 1 Considering the industry success rate for all wells (development and exploratory) was 77.6 percent 2 in1994, 35 percent is not that favourable, especially when one considers that horizontal wells are normally drilled in developed areas. Several authors. 3–8 have recognized the need for a thorough reservoir description through a multidisciplined approach, in order to achieve high success rates with horizontal wells. The additional complexities and uncertainties introduced by horizontal wellbores make convectional analytical techniques, such as electrical logging. 9–12 and pressure transient analysis. 13–15 difficult. Assumptions regarding flow geometry and productivity predictions become uncertain. 16 Joshi. 17 emphasizes that an u