Abstract Working in offshore environments comes with unique challenges and risks, and extra precautions and safety measures coupled with strict environmental compliance must be applied. Contrary to the common belief that strict safety enforcements could hinder smooth operations, the deployment of technological advancements and innovation of processes has enabled operational excellence in offshore operations and overcome several operational challenges, especially in safety performance. This paper demonstrates the health, safety and environment (HSE) performance improvement features of specific initiatives implemented in offshore fields along with the operational advantages and cost reduction. The initiatives include the installation of cableless pressure sensor technology, the deployment of permanent monitoring systems in key wells to provide continuous real-time pressure data to monitor reservoir pressure. Optimizing the operation cost while maintaining the highest level of safety is a global focus of all petroleum companies. Several business techniques help reduce costs while maintain profitability and competitiveness. This is achieved through a dedicated team working in a state of the art Production Operations Surveillance Hub (POSH), which enables the monitoring of wells in real time and making production optimization decisions. These initiatives also demonstrate that safety and operational excellence from new technology deployment and job process optimization for well intervention operations are not mutually exclusive. When a new technology is foreseen as potentially applicable offshore for value addition, focus is paid to its genetic benefits, especially in improving operational flexibility and avoiding risks. Although the deployment of new technology is challenging in offshore environments, using such new technologies and objective oriented processes have helped to revolutionize safety standards in the company and minimize the exposure of personnel - while guaranteeing safer, more efficient operations that have resulted in the elimination of negative environmental consequences and the reduction of operating cost.

Abstract Acid fracturing is a sensitive stimulation technique that has been widely used by the oil industry, but it is limited to so many considerations. An acid fracturing treatment must produce a conductive flow channel long enough to alter the flow pattern in the reservoir from a radial pattern to one that approaches linear flow. This needs a high rate of acid flow completed with formation solution in acid. Considering the above restrictions imposed by acid fracturing, its applicability is limited to special cases where no better solution is available especially in Iranian oil fields. In this paper, one of these special cases is studied occurred in a carbonate reservoir in Iran. This was the first successful acid fracturing operation in an Iranian reservoir which makes the condition so delicate and unique as there was so many uncertainties and lack of experience. Introduction As we know, hydraulic fracturing has been used worldwide in damaged formations and formations with low conductivity but performing acid fracturing has been limited to so many operational and reservoir restriction. The main difference between acid fracturing and proppant fracturing is the way fracture conductivity is created. In proppant fracturing, a propping agent is used to prop open the fracture after the treatment is completed [1], [2]. In acid fracturing, acid is used to etch channels in the rock that comprise the walls of the fracture. Thus, the rock has to be partially soluble in acid, so that channels can be etched in the fracture walls [3]. As such, the application of acid fracturing is confined to carbonate reservoirs and should never be used to stimulate sandstone, shale, or coal-seam reservoirs. Long etched fractures are difficult to obtain, because of high leakoff and rapid acid reaction with the formation [3]. Two major problems of acid fracturing are fracture closure and fracture plugging. Fracture closure occurs in the absence of proppant in high pressure reservoirs. So, acid fracturing is usually limited to low pressure and shallow reservoirs. On the other hand, in some formations, regular or high strength acid fracturing may not provide sustainable production increase if large quantities of fines are released in the fracturing by the acid treatment, thus blocking the fracture. Also high strength acid may over-etch some very soluble carbonates, resulting the crushing of the pillars and post after the fracturing pressure is released or at the later date when the reservoir pressure declines. Thus, the fracture would close, blocking linear flow paths to the wellbore. So, for successful acid fracturing operation formation must be studied [3].

Abstract Tight gas reservoirs are often characterized by complex geological and petrophysical systems as well as heterogeneities at all scales. In addition, the operating environment is very challenging and that affects the decisions for data acquisition. The use of salt-saturated or oil based mud systems creates a contrast and uncertainty in the data. Hence, the quality of static log and core data acquired is compromised. In May of 2008 Shell's Global Wells and Exploration Management made a strategic commitment for the use of underbalanced drilling (UBD) for reservoir characterization on all tight gas exploration and appraisal wells. UBD is unique in that, when properly applied, it completely eliminates any uncertainty of drilling or completion fluid damage from the dynamic gas mobility understanding. Specifically the technology has been used in the exploratory and appraisal campaigns to obtain the direct benefits of characterizing the reservoir while drilling, obtain the real net productive pay zones of the reservoirs, establish whether open fractures were crossed, determining reservoir volumes connectivity and obtaining other important reservoir properties in real time, which helped in calibrating the reservoir models. Gas flowing during UBD has been used to optimize the testing, logging and completion plans that were conducted after drilling each of the exploratory wells. Since 2008 Shell has successfully deployed UBD for tight gas exploration and appraisal on 10 projects in North America, North Africa, the Middle East and Asia. This paper will evaluate the strategic learning's from this deployment of UBD. Evaluation scope will include HSE, project delivery issues, reservoir learning's and changes to sub-surface team's work flows to exploit the information. Selected project results will be presented to support the evaluation conclusions. Discussions will include a view to the future including how Shell is changing overall tight gas project development with UBD de-risking.

Abstract Notwithstanding the odd reduction owing to specific financial or economic situations, the demand for hydrocarbons has grown steadily in the past and is set to follow the same trend in the future. In parallel to the increase in demand, the production from mature fields is regularly decreasing. The upstream oil industry now faces a major challenge to increase production through the continuous development of new hydrocarbon fields. The need to satisfy the world's growing thirst for hydrocarbons means producing from oil and gas fields at ever greater depths (deeply buried reservoirs), or under ever deeper water depths (-ultra- deep offshore). Our industry has begun to tackle developments that require considerable technological boldness to produce: ? either deeply buried reservoirs characterised by High Pressures and High Temperatures (HP/HT) with all the problems generated by these extreme conditions, ? or reservoirs located at great water depths: these fields have to be developed; sometimes satellite reservoirs have to be tied back to a very distant processing unit, while coping with the difficulties of producing more and more viscous oils. Through use of representative examples this session will illustrate some of the technical challenges that our industry has experienced, or still has to face, the ground-breaking solutions that have already been found, and the innovations we hope to see in the next few years.

ABSTRACT Many analysts rely on derivative curve of pressure transient data to diagnose wellbore storage effect and flow regimes to quantify permeability and skin. However, there are field examples that the time at which WBS becomes negligible, can't be determined for further well test interpretation. During transient tests, both pressure and temperature change depending on downhole flow rate. In gas producing wells, Joule-Thomson cooling and frictional heating effects are the main dynamic factors causing sandface temperature to differ from the original formation temperature at that depth. When a gas well is shut in, JT cooling effect is vanished and this causes a sharp increase in sandface temperature. When effect of WBS ends, wellbore temperature gradually cools down due to heat conduction with near wellbore region. Temperature transient data during pressure build up test can be used to detect end of wellbore storage and to guarantee flow regimes on pressure transient data for accurate interpretation in order to improve permeability and skin estimation. A few field examples conducted in oil and gas wells demonstrated that the time attributed to end of WBS could accurately be determined using temperature transient data. For gas wells, effect of WBS becomes negligible at the time increasing trend of wellbore temperature ends. Also, analysis of temperature transient data during drawdown and buildup tests can evaluate reservoir permeability and skin qualitatively. Temperature transient analysis is a fast and reliable tool for qualitative evaluating of skin and well productivity and determining end of WBS in gas producing wells, which can help for more accurate well test interpretation. For gas wells, flowing wellbore temperature can be lower or higher than static reservoir temperature depending on magnitude of JT cooling effect, well productivity and skin.

Abstract: In naturally fractured reservoirs, there usually developed many scales of fractures, from multidarcy large fractures to hundreds of milli-darcy small fractures and even to milli-darcy matrix. This results in multi-scale flow in the subsurface and makes it tougher to analyze well productivity. In this paper, multi-rate well testing data were used to predict the well productivity at different pressure in naturally fractured reservoirs. This method is exemplified with a case reservoir in China. The predictions are very close to later field production data. We conclude that oil production rate in these kinds of reservoirs is not only impacted by both two-phase flow and non-Darcy flow as in the conventional reservoirs, but also impacted by the variation of fracture opening with reservoir pressure. This conclusion can be used to better define optimal rate with reservoir pressure decline in the naturally fractured reservoirs, thus further improve our forecast and enhance our reservoir development results. Introduction Many detailed studies have been done and lots of papers published on productivities of artificially fractured well. For example, McGuire, W.J. and Siora [1] , V.J, Prats, M. and Levine, J.S [2] ; van Poollen, H.K., Tkrsley, J.M. and Saunders, C.D. [3] and Oberwinkler, C. et al [4] have investigated the effect of fracture length and conductivity on post-fracture well productivity for vertically fractured reservoirs assuming pseudo steady-state or steady-state flow in the reservoir and fracture height equal to the reservoir thickness. Later, Tinsley [5] et al investigated the relationship between fracture height and well productivity for cases assuming that the fracture height was equal to or less than the reservoir thickness. All of these works employed two-dimensional mathematical or physical analogy models to predict post thickness fracture well productivity. However, for naturally fractured wells, literatures on the well productivity are limited. The unique characterization of natural fractures makes its well productivity performance different with that of the artificially fractured well. Due to the decline of reservoir pressure, the fracture opening in the reservoir, especially that near the wellbore area, will decrease, which will result in the loss of permeability near wellbore. This permeability loss will impact the well productivity and should be taken into careful consideration when designing the field development. With the increase of oil and gas production from naturally fractured reservoir, the reservoir properties and production performance of this reservoir show a unique behaviour, which is different from the homogeneous reservoir. This uniqueness should be studied to ease our effort to predict later reservoir performance. In 2004, Joshi R [6] described a field case study of Hunton Formation in West Carney Field in Oklahoma. The targeted formation is geologically complex with a large number of fractures. Some of the unique characteristics of the field include decreasing GOR at the beginning of production, increase in GOR after shut-in and sustained oil rates over long periods of time. The authors successfully used material balance and compositional flow simulation technique to reproduce the unique characteristics of the field.

Abstract: Girassol and Jasmim are two deep-offshore oil fields in Angola Block 17, operated by TOTAL E&P Angola. The development of the fields calls for drilling a total of 40 wells. Girassol has been on production since December 2001, while Jasmim started in November 2003. Among all the solutions implemented to help minimise well interventions, always extremely costly in deep-offshore environment, the most valuable for reservoir engineering have been the downhole permanent gauge (DHPG) and the downhole flow-control devices (smart completion). DHPG have been installed on all producers, and on selected water injectors. They have proven invaluable for the understanding of intra-reservoir and inter-channel systems communications, assisting in optimisation of well locations and reservoir management decisions. DHPG have been used for: – daily pressure and temperature monitoring – interference tests - mostly performed in the early life of the reservoirs to assess communication through faults and reservoir characteristics between wells – pressure transient analysis - data have been routinely recorded during operational shutdowns to minimise wells production downtime – remote pressure surveys - before a well is connected, an acoustic module and transducer is lowered on the wellhead and electrical data from DHPG are converted into acoustic signal that can be read by a sensor located on sea surface. This allows to monitor the static pressure and measure the interference with other wells. On Jasmim field, a few wells have been equipped with a smart completion. The equipment allows independent and progressive downhole control of the flow from separate reservoir units, according to their potential and evolution. One year after the first installation, the smart completions have met the demanding expectations of both Completion and Reservoir Engineers. INTRODUCTION This paper presents some of the techniques used on Girassol and Jasmin fields for monitoring and flow control that proved to be very useful for the optimisation of the development. The Girassol and Jasmim fields are located offshore Angola on Block 17 about 150 Km off the Angolan coast. The block 17 is operated by Total E&P Angola under a Production Sharing Agreement (PSA), between the concessionaire Sonangol and the contractor group including Total (40%), Esso (20%), BP (16.66 %, Statoil (13.33%) and Nork Hydro (10%). The Girassol turbidite channels reservoir was in 1996 the first discovery of Total E&P Angola on this prolific deep offshore Block 17, presenting a good oil quality (32°API) and excellent reservoir characteristics. Jasmim field, laying about 5 km westwards of Girassol was discovered in 2000, among the other discoveries on Block 17 (Rosa, Lirio, Cravo, Violeta, Orquidea, Dalia, Tulipa, Anturio, Camelia, Perpetua, Zinia, Hortensia and Acacia). The Jasmim field is in communication with Girassol. Girassol was one of the first Western African deep offshore projects to be put into production, in December 2001. The water depth (about 1400 m), its size (about 15 Km × 10 Km) and unconsolidated sands are at the origin of many technical challenges. Jasmim production started in November 2003.

Abstract: This paper discusses the complex evaluation of a basement reservoir in south-eastern Hungary. The host rock is gneiss with negligible porosity; hence the recoverable petroleum rests mainly in fractures. Commercial exploitation of the field started in the early 1980s. After producing more than 1.3 MMm 3 oil, currently has reached the phase of significant production decline. Since the oil accumulated in and is produced through major fracture zones, conventional G&G studies in general and petrophysical studies based on cores in particular do not provide insights to the reservoir's flow system. Consequently, first a large scale geological subdivision was done on the basis of compartments defined from the results of history matching and reservoir simulation. This primordial model has been refined using 3D seismic data to identify major conducting paths (=fractured zones) and to quantify heterogeneity by combining coherence with the acoustic impedance. On the basis of this simplified model a lot of future production scenario has been predicted. To reduce the risk profile of the forecasts a Discreet Fracture Network (DFN) Model has been constructed. To establish it the reservoir structure and bulk and pay volume of the field had to be verified, the porosity, fracture intensity had to be re-assessed. The input data and their sources have been as follows: Transmissivity (from PLT's, PI's, single hole tests), Diffusivity data (from lag times in interference tests) Fracture intensity (spatial frequency) (from petrophysical logs, well test statistics, and aperturetotransmissivityrelationships) Orientation of fractures (from borehole image log (CBIL)) Distribution/ spatial frequency of fractures and transmissivities (from flow and no flow zones) The fracture network model was further matched to the seismic response of the field parameters and validated against reservoir pressure history as well as production forecast. Although the model uses only the fracture network (=single phase) it is able to reproduce the major elements of the production history. (Figure in full paper) The Dorozsma field is located in SE Hungary. With two adjacent major fields (Moravaros and Algyo fields) it constitutes the most significant petroleum province of the last 50 years. (OOIP ≈ 115 MMm 3 , OGIP ≈ 105 Tm 3 ). Discovered in 1973, Dorozsma field's development started only ten years after. Varying initial static pressure surveyed in and different bubble point pressures measured for different wells indicated well in advance, that the reservoir had minimum 3 (two major and a small), compartments with identical geology, They have been duly named as the "Central Block" and the "SE Block" Block of well Do-16. (Figure in full paper) The reservoir volume developed in an originally tight metamorphic rock. Tectonic activity produced significant fracture porosity and "casual" fracture network. The only homogeneous property in this field is the heterogeneity. The pressure history with widely scattered data points in space and time suggests that direct connection between the compartments in general locally between drainage areas of wells in particular is poor to moderate or non-existing;

Abstract Matrix acidizing treatments was introduced to Hassi 'Rmel field as a mean of restoring and optimizing wells productivity after work-over operations. If the principle of matrix acidizing appears straightforward, the practice is a mine field of complex decisions. Services companies offers a vast selection of acid systems and diverters. The question that should always be asked before any other is why is the well under producing and then will production increase with matrix acidizing Production may be constricted for a reason other then damage around the borehole. In the latter half of 1998, a large campaign of matrix acidizing treatments began in the Hassi R'Mel gas field. Well testing results had indicated that many of the wells in the field showed extremely high damage skin factors. In some wells it's approached 200. Despite such severe near wellbore damage, the wells in the Hassi R'Mel field are still capable of producing at very high flow rates due to the extremely good reservoir characteristics. Matrix acidizing was evaluated to be the best option to remove this near wellbore formation damage. The acidizing treatments were performed a six month period by three services companies using different acid system. A unique feature of this series of treatments was that a production logging tool (PLT) was run before, immediately after, and 180 days after the acidizing treatments in every well treated. Somme wells shows good response and others not1 The aim of this work is to answer those questions by selecting the right acid system, in order to restore the production rate, without generating other problems. We tried to find correlation between wells history, pressure analysis and tests laboratory results (core flow tests, XR diffraction mineralogy, fluid-rock compatibility, fluid-fluid compatibility, scanning microscopy) in order to find the way to the right acid design. Introduction Sandstone matrix acidizing long has been used as a means of improving production of oil and gas by removing formation damage and increasing permeability of the zone around the wellbore2. Laboratory and field studies have demonstrated the effectiveness of this type of treatment In spite of widespread use, however many formations do not respond satisfactorily to conventional HCl/HF treatments. This normally is attributed to rapid spending of HF near the wellbore. Somme wells show good stimulation but later experience an unusually rapid decline in production rate. The decline usually are attributed to plugging by migratory clays and other fines3. BLOCK 1 - - FORUM 3 261 IMPROVING GAS PRODUCTION OF HASSI R'MEL FIELD BY

Abstract. A naturally fractured reservoir called MNSCR reservoir in this study, and situated in southwest or Iran has been acidized for many years without any rule. The objective of this study is to investigate the merits of the acidizing operation against natural depletion in the above mentioned reservoir. Productivity increase in carbonate reservoirs by acidizing is a common and practical technique in the world. Certainly, this technique has been used for both carbonate and sandstone reservoirs of Iranian oil fields in the south to stimulate reservoirs, to remove formation damage and/or make fracture to increase permeability, productivity or injectivity in oil or gas wells. This study was undertaken to investigate the best available scientific methods with due consideration to existing sources and to integrate them with the practical experience acquired through years of acidizing process and production from MNSCR reservoir, obtain a proper acidizing method, and design a simulator for future operations. Before acidizing the candidate well, by analyzing the data of old tests, the plot of rate versus skin for the well was obtained. Using this plot it could be specified whether acidizing improves the well performance or not. If a great improvement was given to the well by reducing the skin factor, the well was planned for an acid job. After acidizing, the improvement on the well performance was investigated by comparing the Inflow Performance Relationship curves before and after the acidizing. Over 45 build up tests (before and after every acid job) from the above mentioned fractured reservoir have been analyzed using type curve techniques and Horner plot to determine the Skin factor@), permeability(K), reservoir pressure(Pr) and other reservoir parameters. Sixteen wells producing oil were acidized in an effort to reduce/eliminate formation damage caused by either the migration of fines or incompatibility problems due to the invasion of drilling fluids into the formation. The primary objective was to reduce the drawdown to protect the wells while increasing production and improving ultimate recoveries. The basic procedure used in each of the treatments consisted of injecting fluids mixed with the additives. Acidizing of 16 candidate wells in this field has played an important role in increasing their productivity. In fact by reducing the drawdown across the completions, production has been increased on the average value of 120 m3/d/well or 35.9% of the original production rate. I. INTRODUCTION Limestone and dolomite reservoirs constitute one of the largest source of crude oil supply in the world. An estimated value of 65 percent of present production is coming from carbonate reservoirs, located in

Abstract. This paper will address the limits and drainage area concepts from two approaches: the reservoir aspects, and the geophysical-geological aspects. In both approaches use is made whenever possible of seismic attribute analysis and detailed 2D, 3D and 4D seismic interpretation, integrated with other subsurface information, which include well testing, well logging, geological and petrophysical data. The dynamics of drainage areas are illustrated through the discussion of the effects present in four different field cases: the structural position of a well completed in a gas-aquifer system; the lateral sedimentary facies change of the producing formation; natural main fractures running along the crest of an anticline; and simultaneous exploitation of several layers through a common tubing. Finally, a state of the art discussion on 4D seismic technology is presented. It is regarded as an integrated exploration and production technology, that examines changes in seismic amplitudes among repeated 3D surveys, to track the movement of fluids caused by drainage within the reservoir, and map the pathways of migration from deep sources into reservoirs. Detailed analysis of reservoir drainage is accomplished using generalized linear inversion, to decipher the physical parameter changes within the specified reservoir over time. The application of this tool allows identification of undrained or bypassed pays and regions. 4D seismic application so far suggest that there is a much more complicated drainage history in the reservoirs than originally thought, and much more to learn on fluid flow, migration paths and natural recharge of reservoirs. 1. INTRODUCTION The drainage area concept is strictly related to the drainage radius. For production conditions, flow will occur in any portion of the formation across which there is a pressure or potential gradient. If a drawdown test is started under conditions of constant reservoir pressure, a pressure gradient (and flow) can occur only after the effects of the pressure perturbation at the wellbore face, have been transmitted to the specific reservoir volume. Practically the velocity of this pressure disturbance transmission process is physically limited. However, theoretically pressure waves are transmitted at the velocity of sound'. Thus, it can be expected that the pressure disturbance due to production at the well will be transmitted radially outward at the local sonic velocity, the drainage radius being rd = u, t (1) where v, is the velocity of sound in the reservoir. The estimations through Equation (1) should be interpreted as a maximum possible drainage radius. Its main ap

Abstract. The poster deals with the approach used for appraisal of marginal fields in deep water, presenting a recent case history. After the field discovery and a first short term well testing, a feasibility study and a reservoir study were carried out, together with a series of parametric analyses, in order to identify the possible scenarios and to pinpoint the factors criticai for an economic exploitation of the field. The analysis showed that the condition for an economic development of the field was the capability to collect all the reservoir information necessary for deciding on the field development with a single appraisal well. For such a purpose, the following action plan was decided: o 3D seismic survey of the field area; o drilling of the appraisal well in two steps, first vertical drilling with continuous coring and DST's, then drilling o long term production test. the decision whether or not to develop the discovery will be based. risks and optimizing the field development design. of a properly oriented horizontal drain hole; The results of these activities have been used for an integrated multidisciplinary study of the field, on which This type of approach should enable the operator to reduce the delineation costs, while reducing economic APPRAISAL OF MARGINAL FIELDS IN DEEP WATERS: A RECENT CASE HISTORY Hydrocarbon potential of the deepwater area in the South Adriatic sea has been investigated since the late 70s, when AGIP drilled and tested the first well (Rovesti in 955 meters of water). Oil shows were detected and therefore, in the following years (early 80s) a second deep water drilling campaign was started. The wells were located in water depths ranging from 400 to 1100 m and the drilling brought the discovery of several hydrocarbon accumulations. However, although the results from this regional exploration activity were encouraging, the production technology available at that time was not yet capable to cope with the difficult deepwater conditions. Moreover, the envisaged solutions were too expensive, thus practically preventing an economic development of the reserves. Therefore, in the following years a coherent multidisciplinary research programme was started, in order to develop the technologies required for an economic production of the discovered hydrocarbons. After ten years of R&D work and about 100 million U.S.$ of investment, AGIP had available and ready for operational use key in-house developed technology and proprietary know-how related to the whole range of building blocks required for successfully coping with the different possible scenarios that an operator may encounter in deep waters. Consequently, in 1991 the feasibility of putting in production the deepwater fields in the Southern Adriatic was reexamined. A screening study was performed, for evaluating the possible alternati

Abstract. Ethane is primarily used in the production of ethylene which is the backbone of Petrochemical and more specifically polymer industry feedstocks. The 1992 world ethylene installed capacity was 73 million tons with a capacity utilization ratio of 84 percent. By 2002 the installed capacity is estimated to be 95 million tons. Ethane is basically produced from natural gas. Natural gas depending on its source and location could contain anywhere from 1 to 20 percent ethane. Associated natural gas is produced from crude oil separation, generally in four flash stages which reduce in pressure consecutively. As the pressure decreases so does the volume, but the ethane content increase. Since associated gas generally has a larger ethane content compared to well produced gas, nil producing countries are potentially in a more favorable position as far as ethane recovery is concerned. A typical ethane recovery system from sweet natural gas consists of residual water vapor removal, liquifaction and separation of 02' plus components by either chilling or absorption, proceeded by expansion through a turbine. In such a system, ethane recovery is in the order of 80-85 percent. Based on sample gas composition available for gas sources in various countries, their respective oil production (if any), typical gas/oil ratios, and/or gas well productions, the potential recoverable ethane has been estimated. INTRODUCTION Ethane is one of the components generally found in natural gas. Aside from being a fuel, ethane is used in the production of ethylene which is the backbone of petrochemicals feed stocks. Ethylene could be produced from various other sources such as naphtha, LPG, and gas oil. In this presentation, ethane potential in 16 major natural gas producing countries is estimated. Natural gas production There are two sources for natural gas production: Associated gas is the by-product in the production of crude oil. Down stream of the well, crude oil is stabilized by pressure reduction generally in four stages. Gas is produced in each stage. As the pressure decreases so does the quantity of gas, while the ethane content increases (although the ethane content may decrease in the last separation stage). The gas produced as such must go through a dew point depression process in order to meet the pipeline dew point specification. Depending on the composition and dew point specification, the liquid (NGL) thus produced, may contain between 10-30 mole percent ethane. The specification lean 1. Associated gas gas would then contain about 8–12 mole percent ethane. By fractionating the NGL ethane is separated along with propane, butanes, and Pentanes +. Well gas is referred to that produced from gas fields which may contain some entrained condensate. Well gas is generally leaner than associated gas and the ethane content i

Abstract. The recent advent of reservoir simulation models using finite element adaptive methods opens a new gateway for simulating reservoirs with a high degree of geologic detail and without excessive grid counts. Well logging, well test and techniques such as 3D seismic combined with geostatistical interpretations can easily generate very large characterization models. Initialization of finite element models begins with fine gridding in reservoir segments of highly variable data and coarse grids in stable data segments. Wells consisting of refined grids are inserted and geostatistically determined parameters are impressed on to the model. During time stepping adaptive regridding based upon simulation error norms of pressure and saturation takes place refining and unrefining grids as necessary to maintain accuracy with a minimum grid count and run time. The continuous pressure and saturation solutions obtained for every point in the reservoir allow the calculation of velocity vectors and particle tracing which can aid immeasurably for resolving flow near difficult reservoir structures and for displaying accurate fluid movement maps. The use of finite element methods in reservoir simulation should increase rapidly since adaptive techniques have now been proven successful in modeling more than one phase of fluid flow in reservoirs. The recent advent of reservoir simulation models using finite element methods opens new gateways for simulating reservoirs with a high degree of geologic detail and without excessive grid counts. Initialization of traditional finite difference models begins with fine gridding defined by some reservoir characterization model based upon geostatistical interpretations. A single value for each reservoir parameter is impressed into individual grid blocks. Grid counts at this point can easily reach 1 million. In order to be tractable grids are usually coarsened (unrefined) to about 100000 grid blocks. Fine grid data must be mathematically averaged to fit the coarse grid. Numerous techniques exist for averaging such as arithmetic, geometric and harmonic. The error introduced by these techniques is highly variable and usually unknown. In all cases the highly resolved data from the characterization model has been lost or substantially altered by the averaging process. Finite element models can employ these traditional grids or for example may use completely unstructured meshes. The output of most commercial characterization models is usually in the form of the vertical square column since this is usable by finite difference models. This grid form is orthogonal in the horizontal direction which greatly reduces finite difference computational errors. Figure 1 shows this type of grid in a fin

Abstract. A semi-analytical model for the production interference of multiple reservoirs sharing a common aquifer is presented in this work. A two dimensional finite aquifer is considered, with nr reservoirs arbitrarily located across the aquifer domain. Water injection is allowed through nw arbitrarily located injection wells. The solution to this problem provides the pressure distribution in the aquifer and the average pressure and water influx for each of the reservoirs as a function of time. The flow behaviour in a given aquifer-reservoirs system was found to be governed by the hydraulic diffusivity, v., and the product pore volume-total compressibility, (V, cr),, of the aquifer and by (V, cr), r = 1,2,. .., nr of the reservoirs. These parameters can be estimated through the model by history matching the average pressure of the reservoirs, the estimation of the water influx in each of the reservoirs is obtained through the matching process. A field application of the model is presented, which consists of the characterization of a system of three naturally fractured reservoirs sharing a common aquifer in the Gulf of Mexico. Parameters estimated through the model were found most valuable as input data for numerical reservoir simulation of the system. INTRODUCTION An important field condition that has been reported in the literature is that of several oil fields sharing a common aquifer'-6. Under these conditions, the reservoirs are in hydrodynamic communication and production from each oil field results in an interference (pressure drop) with respect to the other neighbor reservoirs. This effect should be properly taken into account in all reservoir engineering studies, otherwise with all adverse consequences, performance predictions will fail to match field behavior. This particular field conditions require a special effort for the characterization of the reservoirsaquifer system. In México, the most important producing area is the Campeche Sound. The Abkatun, Pol and Chuc oil fields, situated in a common aquifer, are located in this area. The purpose of this paper is to discuss a semianalytical model, that considers the production interference of reservoirs that share a common aquifer and to present its application to characterize the Abkatun-Pol-Chuc-Aquifer system. MOD EL DESC RI PTION The model is based on the following assumptions: - The aquifer is two-dimensional, of uniform thickness and impermeable boundaries. Reservoirs are arbitrarily located and act as sources to the aquifer. Water may be injected through arbitrarily located wells. Figure 1 illustrates this system. The flow of water in the aquifer is governed by the diffusivity equation. The behavior of each reservoir is described by a conservation equation, which states tha

Abstract. The successful development of an optimum field depletion scheme depends upon early knowledge of the reservoir drive mechanisms and heterogeneities which effect fluid flow in the reservoir. Geophysical, geological, and engineering interpretations must be integrated at an early stage, and any inconsistencies should be resolved. At Terra Nova, this was of particular concern because of the direct impact on the number and placement of producers and injectors in a faulted and compartmentalized reservoir with complex sand architecture. A geophysical evaluation of 3D seismic surveys determined that pay intervals were generally indistinguishable, by velocity contrasts, from surrounding shales and tight conglomerates, thus implying that the reservoir sands could only be mapped indirectly. A mapping method was developed to delineate the intersection of faults with pay zones, thereby identifying seismically-defined fault blocks. Petrographic, petrophysicaÍ, sedimentological, ichnological, biostratigraphic, and dipmeter studies were used to define correlatable lithostratigraphic units and develop a sandstone depositional model, which was utilized in reservoir analysis. Long duration production tests were conducted to evaluate lateral sand continuity through drawdown and buildup analysis and to determine minimum oil in place (OIP) through depletion. The data was analysed with both conventional analytical and numerical simulation techniques, which allowed complex reservoir models to be tested and then compared to the geophysical and geological interpretations. As a result of using a simulator to develop different models, most of the inconsistencies with the interpretations were reconciled resulting in a much better understanding of the reservoir. Résumé. Mener à bien le programme d'exploitation exhaustive d'un champ exige de connaître en temps utile la dynamique du réservoir ainsi que les hétérogénéités pouvant affecter l'écoulement des fluides au sein de celui-ci. Les interprétations géophysiques, géologiques et techniques doivent être introduites dès le début, et les discordances éventuelles résolues. A Terra Nova, ceci était particulièrement préoccupant en raison de l'incidence directe sur le nombre et le positionnement des puits producteurs et des puits d'injection dans un réservoir compartimenté, comportant des failles, et dont les formations présentent une architecture complexe. Une évaluation géophysique des relevés sismiques tridimensionnels a permis de déterminer que les contrastes de vitesse ne permettaient pas, en général, de distinguer les zones productrices des argiles et conglomérats avoisinants, ce qui veut dire que

Abstract. Exploration drilling in the Canadian Beaufort Sea Mackenzie Delta region began in the 1960s, with the first offshore well drilled in 1973 from a man-made gravel island in 3m of water. Reinforced drillships and second-generation drilling equipment have subsequently been introduced, and these have enabled the industry to operate in water as deep as 60 m. Advances in technology associated with the design and construction of these exploratory drilling structures and support systems, together with recorded performance data, provide a sound basis for future oil and gas development. The paper describes a conceptual development plan for the Amauligak field, a major Beaufort Sea reservoir in 30 m of water, with a recoverable reserve potential of 700 to 800 million barrels of high quality crude oil. The processes undertaken to evaluate structural alternatives, producing facilities and the necessary logistics network are also examined. Transportation options-pipeline and tanker-are also discussed. Résume. Les forages d'exploration de la région canadienne du delta Beaufort-Mackenzie ont commencé au milieu des années 1960. Le premier puits marin a été foré en 1973 sur une île de gravier par 3 mètres d'eau. Ensuite, des navires de forage renforcés et la deuxième génération de structures de forage ont été utilisés pour étendre l'exploration à des eaux plus profondes atteignant 60 mètres. L'évolution de la technologie marine de forage d'exploration et des données concernant la réalisation des travaux fournissent une base solide pour le développement futur de gisements de pétrole et de gaz. La communication traite d'un plan de développement pour le champs Amauligak, un gisement en mer Beaufort situé dans 30 mètres d'eau, avec un potentiel de réserves récupérables de 100 à 110 millions de tonnes de brut de haute qualité. On évalue les solutions envisagées pour les structures, les installations de production et le réseau logistique nécessaire. On discute aussi des possibilités de transport-canalisation et tanker. INTRODUCTION The search for oil and gas in the Canadian Arctic has been concentrated in two major areas-the Arctic Islands and the Beaufort Sea/Mackenzie Delta. Large accumulations of hydrocarbons have been discovered in these major exploratory areas. In the Arctic Islands, gas and condensates are predominant; small quantities of oil are also present, but not in economic volumes. In the Beaufort Sea/Mackenzie Delta basin, however, exploration has resulted in the discovery of world class oil and gas pools. This paper traces the chronology of exploration in this area and the accompanying technological advances in the drilling and marine disciplines. These advances f

Abstract. Oil and gas reservoirs of the type where hydrocarbons are contained in fractures and pores are characterized by low oil recovery, and they are difficult to study. Two major types, fractured-porous and inter-layered, are defined for dual-medium reservoirs. Using typical oil fields as examples of dual-medium reservoirs (Salymskoye, Dolny-Dybnik, Nagylengyel), the history of exploration and development, as well as the methods for estimating reserves, have been considered. In the case of the deposits of the Bazhenovskaya formation in the Salymskoye oilfield (West Siberia), there are special difficulties in studying the structure of the reservoirs and selecting the method of development. The oil reservoir is of a bituminous clayey dual-medium rock. To study reservoirs of the above type a new method has been developed for determining the capacity and flow characteristics of the productive media, as well as the method for estimating oil and gas reserves. The method permits characterization of the reservoir and evaluation of the degree of participation of each medium on development under natural drive and displacement of oil by water. In combining geological study of the productive formations with hydrodynamic investigations, the method makes it possible to decide on the means for development, and to increase oil recovery. The method has been tested in a number of oil and gas fields. Résumé. Les réservoirs de pétrole et de gaz particuliers OU les hydrocarbures sont contenus dans les fissures et dans les pores sont caractérisés par un faible taux de récupération et présentent des difficultés pour leur étude. On distingue deux types principaux de réservoirs à milieux complexes: fissurés-poreux et hétérogènesstratifiés. On décrit l'historique de l'exploration et de l'exploitation ainsi que les méthodes de calcul des réserves de quelques gisements particuliers typiques qui sont constitués par des réservoirs à milieu complexe (les champs de Salymskoje, de Dolni-Dybnik, de Nagylengyel). On s'est heurté à de grandes difficultés lors de l'étude de la structure des réservoirs et du choix du procédé d'exploitation de l'accumulation de pétrole de la série de Bashenov du champ de Salymskoje (Sibérie occidentale). Le réservoir est représenté ici

Abstract. Malossa gas-condensate field is the deepest hydrocarbon deposit in production in Europe and one of only three in the world being regularly exploited with a reservoir pressure of over 15000 psi. The gas is overpressured to a large extent in the reservoir, its original pressure being 15 176 psi at a depth of 19 127 ft (water-gas contact). Drilling operations required a considerable effort, especially in casing design, mud and cement technology and drilling control. The very high pressure involved, and the presence in the production stream of corrosive components, originated serious problems in the first wells completed. Extensive use of metal-to-metal seals, use of special steels for the wellhead equipment, recourse to tubing with integral joints and use of an oil-base completion fluid permitted the solution of such problems. The periodical squeezing into the formation of a corrosion inhibitor proved to be beneficial in reducing the corrosion rate to a viable limit. Special care was given to the design and operating procedures of the well-killing system and of the surface equipment control and automatic emergency shutdown system. Malossa field is now in regular production and all problems seem to have been overcome. Résumé. Le gisement de condensat de Malossa est le plus profond gisement d'hydrocarbures en production en Europe et un des trois seuls dans le monde a être régulièrement exploités avec une pression de réservoir de plus de 1055 kg/cm2. Le gaz est largement en surpression, sa pression originale étant de 1067 kg/cm2 à une profondeur de 5830 m (contact eaugaz). Les opérations de forage ont exigé des efforts considérables, particulièrement en ce qui concerne le choix du tubage, la technologie des boues et du ciment et le contrôle du forage. La pression très élevée et la présence dans le fluide produit de composants corrosifs ont provoqué de gros problèmes dans les premiers puits complétés. L'emploi généralisé de joints métal-contre-métal, l'usage d'aciers spéciaux pour l'appareillage des têtes de puits, le recours au tubage avec joints intégraux et l'utilisation d'un fluide de complétion à base d'huile ont permis de surmonter ces problèmes. L'injection périodique dans la formation d'un inhibiteur de corrosion s'est révélé utile pour réduire le degré de corrosion à une limite acceptable. Un soin particulier a été donné à l'étude et au mode opératoire du système d'arrêt d'éruption dans le puits, ainsi que du contrôle des équipements de surface et d'arrêt automatique en cas de danger. Le gisement de Malossa est actuellement en production régulière et tous les problèmes semblent avoir été surmontés. 1. INTRODUCTION Oil exploration of the Mesozoic formations in the Po Valley started

Abstract. The water depth at the Statfjord field is approximately 150 m. The field has recoverable reserves in the order of 400 million tonnes of oil and 70 billion m3 of gas. It is visualized that the full field development will comprise three platforms. A decision on the design of the third platform is, however, not yet taken. The first platform, Statfjord 'A', has a capability of delivering 300 O00 barrels per day of stabilized crude oil into storage for transfer to tankers via a buoy mooring system. The concrete base structure consists of cylindrical cells. Sixteen of these, 20 m dia. and 70 m high, are used for oil storage with a total capacity of 1 200 O00 barrels-equivalent to 3-4 days production. Three of the cylinders extend to a height of 100 m above the top of the storage cells to serve as support towers for the steel deck. The second platform, Statfjord 'B', has a production capacity of 180 O00 barreis per day. The concrete base, which is larger than for Statfjord 'A', permits a larger tow-out weight and has an extended base to accommodate the weaker soil conditions at the site. The number of deck levels is reduced to two (three for Statfjord 'A'). The large deck plan makes possible maximum horizontal separation of the various areas of the platform in a descending order of hazard. Résumé. La profondeur d'eau sur le champ de Statfjord est d'environ 150 m. Le champ a des réserves récupérables de l'ordre de 400 millions de tonnes de pétrole et 70 billions de m3 de gaz. Ou envisage d'utiliser 3 plate-formes pour le développement complet du champ. La décision concernant le projet de la troisième plate-forme n'est cependant pas encore prise. La première plate-forme, Statfjord 'A', a la possibilité de produire et de stocker 300 O00 barils/jour de brut stabilisé pour transfert sur tankers par une bouée de chargement. La structure de la base en béton est composée de cellules cylindriques. Seize de ces dernières (20 m de diamètre et 70 m de haut) sont utilisées comme stockage de pétrole, avec une capacité totale de stockage de 1 200 O00 barils, équivalant à 3 ou 4 jours de production. Dépassant le sommet des de stockage, 3 cellules cylindriques s'élèvent à une hauteur totale de 100 m, pour servir de support au pont métallique supportant les installations. La deuxième plate-forme, Statfjord 'B', a une capacité de production de 180 000 barils/jour. Sa base en béton, plus large que celle de Statfjord 'A', offre des possibilités de remorquage plus grandes. La superfìce de son embase a été accrue pour s'adapter, sur le site, au terrain plus meuble qui doit supporter l'ensemble. Le nombre de niveaux s'élevant au dessus du po