Liu, Bing (Geology Institute of No.1 Oil Production Plant, Daqing Oilfield Co. Ltd.) | Sun, Xiuzhi Sun (Geology Institute of No.1 Oil Production Plant,Daqing Oilfield Co. Ltd.) | Wang, Kun (Testing Brigade of No.1 Oil Production Plant, Daqing Oilfield Co. Ltd.) | Xu, Hong (Geology Institute of No.1 Oil Production Plant, Daqing Oilfield Co. Ltd.) | Liu, Qi (Geology Institute of No.1 Oil Production Plant, Daqing Oilfield Co. Ltd.) | Liu, Xin (School of Environment and Natural Resources) | Song, Shuling
Common polymer flooding on-site tests and industrialized application indicates that conventional polymer flooding gives about a 10% more oil recovery than waterflood, with an ultimate recovery of 51% OOIP. But, because the existence of high permeable zones, this sometimes makes polymer flooding insufficient or ineffective in the reservoir. In some polymer flooding producers, after polymer is breakthrough, water-cut increases rapidly, it adversely affects polymer flooding, resulting in on-site enhancing recovery greatly lower than 20% of laboratory estimates.
In 2002, on the basis of high concentration polymerflooding study in lab, we perform high concentration polymer flooding on-site. By optimizing slug combination and adequate monitoring and analyses, water-cut is greatly decreased, with a decrease percentage of 14.5, this improves polymer flooding development effect. The field test data shows, that high concentration polymer flooding in beginning, recovery has given 4.2% higher than that of conventional polymer flooding by Dec. 2005; and flooded in later stage recovers 3% more oil than conventional method, this indicate that the result of high concentration polymer flooding in initial stages is better than in later stage.
Polymer flooding monitoring and simulation technology predicts that 19.8% more oil can be recovered than water flooding, with a production degree of 61% OOIP. On-site high concentration polymer flooding recovery is two times of the conventional polymer.
The pilot tests and commercial production of polymer flood in Daqing Oilfield indicate the present oil recovery by conventional polymer flood can enhance 12% or so and the ultimate recovery efficiency can achieve 53% OOIP. However, because of the reservoir heterogeneities, the great difference of physical properties leads to the injection profiles reversed and polymer injection with inefficient cycle in some well groups that locate in high permeability and thick zones. With the breakthrough of polymer solution, the water cut obviously goes up and the oil production greatly declines. The oil recovery efficiency is not high, so there is still considerable residual oil underground. Therefore, a new technology is urgently needed to further improve polymer flood.
The case study on pilot test of high concentration polymer flood in the ZQXB Block of Sazhong area, Daqing Oilfield
1. Laboratory Studies of High Concentration Polymer
To satisfy the needs for further improving polymer flood, first of all, a great deal of laboratory studies are conducted in Daqing Oilfield. The study results show that the higher concentration of injected polymer, the higher the oil recovery of polymer flood is, and with the concentration further increased, the oil recovery will continue to go up, which mainly benefits from the viscoelasticity of polymer solution. For high permeable reservoirs, it is particularly needed to use the polymer solution with high viscoelasticity to enhance oil recovery to the utmost.
The core test results present when the oil recovery has been enhanced by 10%OOIP with common concentration polymer driven after waterdrive (watercut 98%), it will be further boosted with increasing of polymer concentration. The main reason is the viscoelasticity of polyacrylamide. By use of the viscoelasticity of polymer solution, the oil recovery of polymer flood can be 20% higher than that of water flood. From table 1, we can see the oil recovery with high concentration polymer flood at different stage of polymerflood is 22.86-27.61% higher than that of water flood(Tab.1). The more early high concentration polymer injected, the higher recovery efficiency is; the highest recovery can be obtained by using high concentration polymer during the initial period of conventional polymer injection. The enhanced recovery of high concentration polymer solution is higher than that of ASP flooding.
Dr. D. Wang believes that Polymer could not drive the residual oil in the "blind end?? of pore in water-wet sandstone. The oil in the "blind end?? of pore only is converted to movable oil before it can flow.
Research related to weak elastic wave stimulation of oil reservoirs started in the late 1950's. Activity peaked in the 1970's and 1980's in the US and in the Soviet Union. However in recent years there has been a resurgent interest and research. This interest derives form observations made in some fields near areas affected by earthquakes and, even heavy traffic, where changes in water level and oil production have been observed. For example, some variations in oil production were noticed in Kern County during the Southern California earthquake of July 1952. However, mechanism associated with earthquakes are very complex and variations in oil production or water level could be consequences not only of seismic vibrations, but also of rock fracturing and other effects associated with earthquakes.
Two different types of waves are usually distinguished: high power frequency (around 20 kHz) and low power frequency waves (e.g. 40 Hz).
High power frequency waves have a local effect in the reservoir and are mainly applied for wellbore stimulation. Their effects are limited to a region close to source due to higher sound absorption in the porous medium at higher frequencies.
Low frequency acoustic waves effects can cover a larger region and are consequently used for reservoir, rather than well stimulation. They are generally applied by using surface vibrators, but there are also example of downhole applications.
This paper is primarily focused on waves used for reservoir stimulation, as opposed to well stimulation. It aimed at understanding the main mechanisms associated with the application of vibrational energy in porous media, and assessing laboratory and field studies.
In this paper, together with potential mechanisms, laboratory and field trials are discussed.
When a fluid saturated porous medium is exposed to elastic vibrations the following waves are dispersed into the medium:
The compressional shock wave is mostly attenuated in the proximity of the source. The pressure wave advances much further into the reservoir producing changes in the saturated fluid. Under the effect of such waves, due to inertial forces and differences in density, the saturated phases start to vibrate with respect to their centres and to the other phases.
Part of the elastic vibration produced at the pore surface is attenuated and lost in the medium due to several irreversible processes associated with shear and volumetric viscosity in the medium, e.g. conversion of vibrations are produced at the pore level due to micro-heterogeneity of both the porous medium and the oil-water interface.
The high frequency volumetric pulsations are accompanied by hydrodynamic microflows about the dispersed phases, as well as driftage of the diffusive sublayers around them. This results in loosing and thinning of the surface adsorbed layers around the phases. Some authors believe that this is likely to be the reason why reductions in interfactial tension and contact angle occur.
This technology is believed to have a number of enhancing effects on oil recovery through:
Following these mechanisms are discussed in detail.
The technical and economic challenges of exploring and producing in deepwater environments require that risk and uncertainty be reduced as much as possible. One of the major contributors to uncertainty - and therefore risk - is creating a sound structural framework. Sophisticated geostatistical techniques are commonly used to create facies and petrophysical models which are used for analyzing uncertainty and making reservoir management decisions, but the underlying structural frameworks often do not correctly portray the true structure. Current methodologies have limitations to the types of fault intersections, the number of faults that realistically can be modeled, and/or the type of grid that can be generated from the reservoir model.
The structural framework is often a compromise between the actual structure and what the modeling system allows, particularly in areas with large numbers of Y-intersections, low angle faults, or reverse faults. We have developed a new technique for structural framework building that takes a unique approach to constructing the initial fault model, where fault relationships and intersections are easily defined and controlled.
This technique does not have limitations to the types of fault intersections nor to the number of faults which may be included in a reservoir model, and provides the tools to build a reservoir grid using these complex fault intersections. When the structural framework more accurately represents the interpretation, subsequent calculations such as reserve estimates, analysis of structural uncertainty, or well placement can be made with more confidence.
The simplicity of building and editing the fault relationships, creating the stratigraphic model, and building the reservoir grid means that an asset team can easily update a model, test different interpretations, and use the model for both geologic and engineering applications.
Techniques for mapping and modeling faulted structures have been in existence for nearly 40 years, but asset teams still struggle to create correct portrayals of complexly faulted reservoirs. Two-dimensional techniques first became available in the late 1960s and early 1970s; these mapping algorithms often did not use standard contouring rules to create the 2D grids and therefore could produce impossible or unreasonable structures. With the advent of 3D computer graphics in the 1980s, mapping and modeling expanded into the 3D world as well. Sophisticated algorithms for distributing petrophysical properties or facies in 3D quickly became indispensable, as these techniques provide better information for reserve calculation and well planning than simple 2D maps. However, the modeling of complex structures continued - and continues - to be a problem. Several methods have been developed for fault surface and fault network modeling, each of which has advantages and disadvantages. Most methods have practical, if not absolute, limitations to the number of faults which can be incorporated into a model simply due to the size of the resultant model or the complexity of building the network. Many also have limitations as to the types of fault intersections which can be modeled. As exploration and development continue to expand into increasingly complex and risky areas, the accuracy and usability of the models becomes more and more important. If the fault network on its own was the final desired result, models with hundreds or thousands of faults could be easily created on a regular basis. Many of the problems arise in using the fault framework to create the full, layered structural model and in using that complete framework for reservoir gridding and the subsequent petrophysical and facies modeling. Our method of fault network modeling has been developed to address the limitations of the current methodologies - to eliminate the restrictions on numbers of faults and types of fault intersections, to increase the speed of the process, and to allow the accuracy of the structural framework to be carried into the reservoir grid.
Ferno, Martin Anders (U. of Bergen) | Ersland, Geir (University of Bergen) | Haugen, Asmund (U. of Bergen) | Johannesen, Else Birkeland (Conocophillps) | Graue, Arne (ConocoPhillips) | Stevens, Jim | Howard, James J.
The fracture/matrix transfer and fluid flow behavior in fractured carbonate rock was experimentally investigated using magnetic resonance imaging (MRI). Viscous oil-water displacements in stacked carbonate core plugs were investigated at wettability conditions ranging from strongly water-wet to moderately oil-wet. The impact of wettability and was investigated in a series of flooding experiments. The objective was to determine the impacts on fluid flow from different types of fractures at various wettability conditions. A general-purpose commercial core analysis simulator was used to simulate the flood experiments and to perform a parameter sensitivity study. The results demonstrated how capillary continuity across open fractures may be obtained when wetting phase bridges were established. A viscous component over the open fractures was provided when the wetting preference between the injected fluid and the rock surface allowed the formation of stable wetting phase bridges. The combination of high spatial resolution imaging and rapid data acquisition revealed how the transport mechanisms for oil and water were governed by the wetting affinity between the rock surface and the fluids in the fracture; both at moderately water wet conditions and at moderately oil wet conditions.
Production of oil from naturally fractured reservoirs is commonly governed by co- and counter-current imbibition of water. Imbibition is dependent on wettability due to the controlling capillary forces, and waterflooding fractured reservoirs have been successful in many water-wet reservoirs. Extensive waterflooding over several years in the oil-wet field Ghaba North in Oman, however, resulted in very low oil recovery (around 2 %) as most of the oil was produced from the fractures only. Fractures generally exhibit a relatively small volume of the total porosity in fractured reservoirs (typically 1-3 %), but the fracture network is important for fluid flow due to much higher permeability and the augmentation of accessible surface in which imbibition may occur. In water-wet reservoirs, oil is produced from the matrix to the fracture system by capillary imbibition of water with subsequent oil expulsion.
Capillary continuity between isolated matrix blocks is in general recognized as favorable in fractured reservoirs dominated by gravity drainage. Capillary continuity across fractures in preferentially oil-wet reservoirs may increase ultimate recovery during gas assisted gravity drainage. Capillary continuity in preferentially water-wet reservoirs increases the height of the continuous matrix column and reduces the amount of capillary trapped oil. For oil recovery in fractured reservoirs produced by viscous fluid displacement, establishing stable wetting phase bridges may contribute to added viscous pressure components over isolated matrix blocks, and thus may increase the oil recovery above the spontaneous imbibition potential. Several authors1-3 have shown experimentally that vertical capillary continuity across fractures becomes important when gravity is the driving force. Saidi4 (1987) introduced the idea of capillary continuity through stable liquid bridges. Labastie5 (1990) found that the permeability of the fractured material influenced the ultimate recovery of the gravity drainage; increased permeability lead to increased oil recovery. Stones et al.6 (1992) investigated the effect of overburden pressure and the size of the contact area of the porous material across the fracture. They concluded that the size of the contact area controls the transmissibility of oil, and therefore the ability of the fracture to transport liquids across the fracture. O'Meara Jr. et al.7 (1992) investigated the film drainage along coreholder end-pieces in centrifuge capillary pressure measurements, where they argued that if the conductivity of the film was large enough, the assumption of zero capillary pressure at the outlet end of the plug could be disregarded. Firoozabadi and Markeset8 (1994) observed capillary continuity between isolated matrix blocks by liquid film drainage along non-porous spacers placed inside the fracture, and by liquid bridging forming inside the fracture. They concluded that the film flow and the degree of fracture liquid transmissibility controlled the rate of drainage across a stacked matrix blocks.
Fracture spacing is an important concept for characterizing flow properties of naturally fractured reservoirs, since the main function of fractures that separate matrix blocks is transporting fluids through long distances; however, the estimation of fracture spacing presents some difficulties mainly due to the fact that fractures occur at different scales, going from microfractures in thin sections and minifractures in cores, up to macrofractures in geological outcrops. The scale of interest in this work is that used in reservoir simulation, which is of the order of feet or meters.
This article is based on the ideas developed in a previous paper, where a procedure to locate fractures is presented. That procedure, which makes use of resistivity data obtained through well logging, visualizes the fractures as highly conducting channels within a low conductivity medium (the rock matrix). By using a special way of data processing, it is possible to filter out data that are not associated with fractures, keeping only those data related to fractures. In this way, fracture spacing can easily be estimated. However, that procedure exhibits some uncertainties which must be overcome to make it a more reliable one.
In this work, a study is made to search for an improved procedure to estimate fracture spacing. For this purpose, fractures are considered at two scales: local scale which includes micro- and minifractures present in matrix blocks, and at reservoir scale which refers to fractures separating matrix blocks. These latter fractures, called principal fractures, constitute the main fracture network, and are the subject matter of this work.
Conductivity studies reveal that local scale fractures have a frequency distribution quite different from that of principal fractures. As it will be seen below, this fact facilitates establishing a procedure for estimating fracture spacing without uncertainties.
To make the ideas clear, an application to a carbonate reservoir is presented. The results obtained show that the improved procedure is a simple, reliable, and practical tool for establishing the distribution of fractures along a well, from which fracture spacing can be inferred.
Non sealed fractures in naturally fractured reservoirs are high conductivity channels; hence, fracture spacing is a factor that controls, to a great extent, the flow properties of such systems. In spite of its importance in areas such as hydrology, geology, geophysics, and petroleum engineering, the problem of estimating fracture spacing has not received the proper attention from researchers, and the specialized literature presents relatively few works treating in depth this theme. Among the currently used techniques for detecting fractures are well testing, core analysis, direct outcrop observation, and well logging.1-4 In this work, an improved way to determine fracture spacing is approached.
In a previous paper,5 a procedure for estimating fracture spacing was developed. That procedure is based on data analysis of formation resistivity factor obtained through well logging. The fundamental consideration of the procedure is that fractures are high conductivity anomalies in a low conductivity medium (the matrix) and, consequently, the basic tool for studying fracture spacing is based on the detection of contrasts in electrical conductivity. To this end, a special analyzing process is used to distinguish between data associated with fractures and non-associated. However, such a procedure does not allow establishing with certainty a discriminating threshold between both types of data.
The fractures referred to in this work are those surrounding matrix blocks. These fractures, called principal fractures, constitute the main fracture network, which has the property of transporting reservoir fluids through long distances, and eventually to the producing wells, in opposition to micro- and minifractures which act at block scale, and whose main function is to convey fluids within the matrix blocks and towards the principal fractures.
Nares, Ruben (Instituto Mexicano del Petroleo) | Schacht-Hernandez, Persi (Instituto Mexicano del Petroleo) | Ramirez-Garnica, Marco Antonio (Inst. Mexicano del Petroleo) | Cabrera-Reyes, Maria del Carmen (Instituto Mexicano del Petroleo)
In this paper the effects of some ionic liquids elaborated with iron and molybdenum used to upgrade the properties of a heavy crude oil are discussed. The underlying objective is to increase the mobility of the oil in the reservoir reducing viscosity and improving the oil quality (e.g. diminishing the asphaltene and sulfur contents and increasing its °API gravity), using ionic liquids based on iron (10 wt%) and molybdenum (2 wt%) compounds, in a liquid phase homogeneously mixed with heavy crude oil in a batch reactor of 500 ml, at 673 K during 4 hours. The API gravity of a offshore heavy crude oil from the Gulf of Mexico increased from 12.5 until 20, kinematics viscosity decreased from 15,416 to 136.63 cSt at 288.75 K, asphaltene content was reduced from 28.65 to 10.82 wt%, while the sulfur was removed from 5.14 to 2.16%; and the distillation obtained by Simulated Distillation was increased from 48 to 71.2 vol%.
Content of aromatics and saturated compounds were increased through the conversion of asphaltenes and resins, which contents decreased from 16.81 to 13.8 wt% and from 28.85 to 10.82 wt% respectively. Finally, the content of total nitrogen was reduced from 780 to 633 ppm in weight which represents a reduction approximately of 20 wt%.
In this work upgrading of a heavy crude oil was obtained through the application of the thermal and catalytic hydrocracking with an ionic liquid. This ionic liquid could be applied into the reservoir combined with in-situ combustion process using unconventional wells in order to improve the recovery of heavy crude oil, producing an oil improved in-situ with lower viscosity, being easier their exploitation, increasing the productivity index in wells, and saving costs of transportation and refining at surface.
Improving some oil properties as oil viscosity reduction and increasing API gravity are key properties to increase the wells productivity index of heavy crude oil. The thermal methods occupy an important place among enhance oil recovery techniques, especially in the production of high-viscosity oils and natural bitumen . Different versions of thermal methods are used to upgrade heavy crude oil, among the more important methods are Steam Drive [2-4], Cycle Steam Injection , Steam Assisted Gravity Drainage (SAGD) [6, 7], Conventional Fire Flood [8, 9], Toe-to-Heel Air Injection Process (THAI) [10-12], Aquathermolysis [13, 14], and Down-Hole Catalytic Processes [15-17].
The last process mentioned is an interesting alternative to reduce of viscosity of the heavy crude oil improving the oil quality inside the reservoir. In order to be carried out the last process is necessary to combine the in-situ combustion process with a liquid consists only of ions [18-20] of metallic salts. The iron-base ionic liquid  would be distributed throughout the reservoir as a diluted salt solution. The polar molecules of the heavy crude oil probably would be diffused in ionic liquid favoring the contact between both phases. On the other hand, the iron-based ionic liquid may be modified during the preparation with anionic sulfates (SO42-) and promoters in a small percentage of transition metal such as molybdenum or tungsten. The metals compounds in the ionic liquid have been recognized because their catalytic properties in hydrocarbon oxidation, cracking, and hydrocracking reactions. In contrast, the metal also accelerated oxidation indirectly by destroying the antioxidants  that are naturally present in the most crude oil.
In the present work the upgrading of the heavy crude oil from the Gulf of Mexico was carried out in a batch reactor as well as a continuous-stirred tank reactor (CSTR). The API gravity was increased from 13.5 until 20o, the kinematics viscosity was reduce from 15,416 to 136.63 cSt at 289 K, the hydrodesulfuration was reduced between 40-60 wt%, and the distillable fraction was increased from 48 to 71.2 vol.% which was carried out by True Boiling Point (TBP).
The catalyst was prepared using ferric sulfate hydrate, water, phosphoric acid and phosphotungstic acid compounds.
The invasion of pulverized rock formation grains and the resulting "low-permeability crushed zone?? is the primary cause of wellbore damage in perforated completions, as established by Behrmann et. al. In order to minimize this damage during the perforating process, it is necessary to provide a dynamic underbalance in the well that will deliberately induce flow into the wellbore for tunnel cleanup. Traditional well fluids have a limited application in depleted reservoirs as the lowest achievable density is on the order of 6.6 ppg. In many depleted reservoirs this density can represent an overbalance. It is not always desirable or operationally practical to provide this underbalance with a gas cushion, and therefore in order to achieve underbalance, it is desirable to engineer a stable fluid with non-damaging chemical properties that would have a significantly lower density. This paper reports on the formulation of super light completion fluids consisting of Shell Sarapar 147 synthetic oil [Shell MDS (M)], 3M™ Glass Bubbles as a density reducing agent and an appropriate rheology control agent. Laboratory tests show that density values as low as 5.0 ppg could be achieved. Similar mixtures were prepared and used in perforation operations for Talisman's Malaysia. A total of 72 barrels of lightweight completion fluids at about 5.5 ppg was pumped downhole and the perforation job completed successfully. Production history of the well shows a marked increase in production rate compared to neighboring wells, which produce from the same reservoir, but were perforated traditionally. This technology is not necessarily limited to depleted reservoirs. In normally pressured zones where permeability is extremely low, the fluid provides an opportunity to increase the available underbalance by an order of magnitude to assist cleanup.
It is no secret that perforations conducted in overbalanced conditions can result in damage of the rock matrix. The damage zone usually extends about 1 centimeter into the rock with about 20 percent or more of permeability reduction9. Lower permeability rocks tend to exhibit a larger percentage of permeability reduction. The damage zone of the rock matrix occurs from the crushing of sand grains as the jet enters the rock. Figure 1 shows a typical perforation schematic of rock perforated in an overbalanced state. It indicates the presence of perforation debris and a low permeability zone of crushed and compacted material around the perforation tunnel. Perforating shock waves and high impact pressure shatter rock grains that break down inter-granular mineral cementation and de-bond clay particles, creating a low permeability crushed zone in the formation around perforation tunnels. It is essential to remove some or all of the perforation damage to ensure a successful perforation job9. A common practice is to conduct perforation cleanup through acidizing. This type of clean-up job imposes additional costs. Perforation cleanup or remedial perforation-wash acid jobs could be avoided if the perforation operation were conducted in an underbalanced state. Underbalance perforation is widely accepted as the most efficient method to obtain clean perforation. Optimal underbalance pressure criteria have increased substantially over the past decade as a result of hundreds of laboratory tests and field observations1,4. Field observations by King et. al were used to develop criteria based on the efficiency of sandstone acidizing. Behram correlated laboratory data with the viscous drag force to remove fine particles in perforation tunnels. Laboratory tests confirm that a higher degree of underbalance is indeed needed for clean perforation. Underbalanced perforation improves flow channels by effectively removing the crushed zone. This is achieved through an instantaneous surge of fluids from the reservoir into the wellbore when the jet penetrates the rock. Thus underbalance perforation aids in the removal of perforating debris, while minimizing or eliminating crushed-zone damage in and around the perforation tunnel.
Oil production in Egypt is based on the development of mature fields with highly complex geological and reservoir characteristics; therefore, a great amount of creativity is required to operate these oil fields. One of the main elements for development of mature fields is to estimate the reserves and determine the amount and location of the remaining oil.
Material balance equations have been used in petroleum engineering for many years to estimate the original hydrocarbon in place. This paper documents the ability of using the analysis of the material balance results in the reservoir characterization and determination of the remaining oil location. The applicability of this work is confirmed by actual field case study (Shukheir Bay Field) in Offshore Shukheir Oil Company (an international joint venture company in Egypt). Such study is an original contribution to the knowledge of the material balance results analysis.
The material balance equation in the reservoir engineering is based on the principle of the conservation of mass (Mass of fluids originally in place = Fluids produced + Remaining fluids in place). The general form of the material balance equation was first presented by Schilthuis in 1941.1 In this equation; the cumulative withdrawal of reservoir fluids is equated to the combined effects of fluid expansion in the reservoir resulting from a finite pressure drop, pore volume compaction, and water influx. In 1963, Havlena and Odeh2,3 presented techniques for interpreting the material balance equation as a straight line, which makes it easy to apply graphical techniques. In particular, extrapolation of a straight line allows the prediction of future reservoir performance, while the parameters of the line often are simply related to in-place volumes or water influx performance.4
The results of the material balance calculations are affected strongly by the selection of the PVT data. The gas liberation in the reservoir changes with the reservoir pressure. In the case of reservoir fluids above/at the bubble point, as the pressure decline due to withdrawals, the gas librated from oil does not flow to the well but accumulates until the critical gas saturation is reached. When the critical gas saturation is reached near the well bore, the gas may be moving more rapidly than the oil (differential liberation) whereas the remainder of the area the liberated gas remains in contact with the oil (flash liberation). Therefore, flash liberation data more closely represent the reservoir liberation process.5
Shukheir Bay Field
Data used in this research was obtained from Shukheir Bay field (Offshore Shukheir Oil Company - OSOCO), which is located in the shallow water close to the western coast of the southern part of Gulf of Suez (about 20 km south of Gharib - Egypt- Fig. 1). The field has been developed by drilling four deviated wells from the shore line. Three wells (SHB-1, SHB-2 and SHB-4st) are completed in Lower Rudies Sands while the fourth well (SHB-3st) is completed in Karim formation.
In December 1980, Well SHB-1 was completed on Lower Rudies Upper Sand (Pay I) and started production with 2200 BOPD and 0.8 MMSCF/D gas. The initial reservoir pressure is 2470 psi; however, the bubble point pressure of the produced oil is 2241 psig. Since December 1980 till now, the main reservoir (Lower Rudies Sands) has produced a cumulative of about 5 MMSTB of 34 API gravity oil from two pay zones (Pay I and Pay II) through two wells (Wells SHB-1 and SHB-4st). Well SHB-2 was completed in an isolated dry zone and Well SHB-3 was completed in another formation (Karim Formation). The production performance curve of Lower Rudies Upper Sands (Pay I and Pay II) is shown in Fig. 2. Currently, the main producing well (Well SHB-1) is on jet pumping producing about 700 BOPD with 70% water cut and estimated GOR of 680 SCF/B. The reservoir pressure declined to its current value of about 1800 psig.
Recently, a complete reservoir study for the development of Shukheir Bay Field was performed. Material balance equation was used through the study to (1) estimate the original oil in place and the reservoir driving mechanisms, (2) identify the reservoir characteristics and provide more geological, engineering and structural understanding of the Lower Rudies reservoir, and (3) define the best location(s) of new producer(s) to be drilled in order to increase field production and enhance the recovery factor.7
A new mechanistic model for two-phase flow in vertical and inclined pipes was proposed based on Drift-Flux approach. The proposed model, unlike the other mechanistic models (Ansari et al., Xiao et al., Unified Mechanistic Model), which incorporate a system of nonlinear equation to solve, uses an explicit equation for liquid holdup prediction thus reducing computation time significantly. Coupled with some simplified assumptions on PVT, such simple form of liquid holdup prediction formula enables analytical integration of pressure gradient in two-phase flow along the pipe. This procedure is usually used to speed-up calculation of bottom-hole pressure for large number wells for oil production optimization purposes.
Drift-flux approach can predict liquid holdup for bubbly flow quite accurately. But for slug flow, it usually underestimates the void fraction. Since slug flow is the most common in producing wells, this leads to the pressure drop being overestimated significantly, that can be proved comparing computational results to the experimental data and mechanistic models. Small gas bubbles in liquid slugs should be taken into account to predict liquid holdup for slug flow more accurately. Gas in slug body is considered by adding a proper term to the void fraction expression. This term is based on correlation for liquid holdup in slug body. The model was evaluated using Rosneft field data and TUFFP databank. Evaluation of the model was made in comparison with three other mechanistic models for multiphase flow
The major tasks for every oil company are oil production maximization and operational costs reduction. This requires permanent well production monitoring with selecting the most promising wells and performing operations on those wells to increase production (well enhancement routines). The key objective of well production monitoring is to control productivity index and well potential for every well during the well lifecycle. This requires the well bottomhole pressure (BHP) to be determined. In some cases direct measurement of the Bottomhole is either difficult or economically insufficient, that's why BHP calculation is still a relevant problem.
The complexity of pressure gradient prediction grows out of multiphase character of mixture flowing through oil wells. The multiphase mechanistic models1,2,3 allow prediction of pressure gradient with high accuracy for the whole range of pipe inclination angles and input parameters. Such models are applicable for detailed analysis, but since they usually incorporate a system of nonlinear equation to solve, the computation time can be quite significant.
When the oil company operates the number of thousands wells, it is important to implement their regular analysis to choose the wells, optimization of which would be most beneficial5. For such case, usage of mechanistic models can be rather difficult because of their iterative procedure leading to large computation times required.
The purpose of this paper is to develop a simple mechanistic model for pressure gradient prediction that
The development of new oilfield technologies to explore such remote areas as deep waters and environmentally sensitive locations brings with it increased emphasis on protecting the natural resources of the drilling area. Accordingly, many regulatory agencies demanding zero discharge policies require all generated wastes to be disposed in a responsible manner. Such process requires the adequate management of wastes generated during drilling operations including cuttings, excess drilling fluid, contaminated rainwater, produced water, scale, produced sand, and even production and cleanup waste. Old practices involve temporary box storage and hauling of the waste products to a final disposal site. Often, these sites are several kilometers away from the generation source, creating not only liabilities for the operating company but also environmental risks such as accidental spills, gas emissions and eventually high operating costs.
Over the years, waste management technologies have evolved to address environmental solutions in the most efficient and cost-effective processes. As such, Cutting Re-Injection (CRI) nowadays is considered top-of-the line technology for the final disposal of drilling wastes through sub-surface injection into an engineered-designated formation where wastes are permanently contained. Transporting the wastes to the final disposal well poses a challenge in large development fields, where the most cost-effective solution is often to drill a dedicated injector and convey all produced wastes to the site.
This paper addresses the success of integrating methodologies for containing, handling, and transporting drill cuttings from several drill sites to a unique CRI well, where wastes are injected for final and responsible disposal. Case histories of several sites around the world are presented as they used different process configurations to achieve the common final objective: a cost-effective and environmentally friendly solution for waste management.
The three main drivers for the selection of a cuttings collection and transport system and re-injection package are regulations, logistics and cost.
Depending on the country, region or marine area, the existing regulations may or may not allow discharge or transportation of the waste. In some areas where legislations are less stringent, transportation of generated waste to satellite disposal sites (in land or offshore) is allowed. In highly sensitive areas in which zero discharge policies are strictly enforced, all generated waste must be stored, treated and disposed in-situ. Because of such limitations, drilling operations were often limited by the collection capacity and ability of the CRI system to inject all waste concurrently. The new approach is to decouple the injection process from the drilling operation, providing a totally independent cost-effective process.
For the logistics, the main limitations are determined by rig configuration, availability of space, types of materials, distance of the material transportation, and safety, which ultimately translate into costs. Therefore, each operation should be analyzed individually to determine compliance with local regulations, logistics and cost involved so proper collection, transport and re-injection packages are tailored to fulfill the specific needs of the project.
The best approach to provide the most reliable solution for environmentally safe waste disposal has been identified as the integration of cuttings collection and pneumatic transport system as part of the CRI package.
In general, CRI is a process wherein solids (cuttings) and liquids (waste fluids) are gathered and conveyed to a series of components that classify, degrade, mix, and condition them into an stable and pumpable slurry. This slurry is then hydraulically injected into a subsurface formation that is receptive and permanently isolated at a safe depth beneath a cap-rock to prevent propagation to the surface.