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
Reservoir performance during waterflooding is important to reservoir engineers. Analytical and semi-analytical flow models with different assumptions have been presented and used widely to describe the flow dynamics of such a process. Most assume that one of the terms, typically capillary forces, can be neglected or considered constant diffusion coefficients, so the simplified diffusive-convective type of flow equations can be solved analytically or by numerical methods. Obtaining analytical or semi-analytical solutions to non-linear diffusive-convective flow equations, including capillary, gravity and viscous forces simultaneously, has been a challenge.
This paper presents a theoretical study of the effects that controlling flow parameters have on saturation profiles and breakthrough time during oil recovery by waterflooding. A mathematical non-linear diffusive-convective type model for immiscible oil-water displacement in one-dimensional vertical homogeneous porous media considering the three chief forces (capillary, gravity and viscous) is derived and solved numerically by using a finite-difference formulation with fully implicit scheme in time and central differences in space.
Dimensionless equations are written so that any of the three forces can be investigated independently; capillary and gravity forces can be "turned on or off.?? The effects of varying fluid viscosity, injection flow rate, system length or wettability, for both displacing and displaced fluids, can be understood thoroughly. The flow model is versatile enough that it allows for variations of the shape of the relative permeability and capillary pressure functions. The impact of these functions in the driving forces and on oil recovery is analyzed.
The contribution of each of the forces to the dimensionless water velocity and its impact on oil recovery was studied in four flow cases: viscous, viscous-gravity, viscous-capillary and viscous-gravity-capillary; all possible flow cases in water injection problems were considered. Graphical results are discussed.
In primary recovery stage, a reservoir's energy is due to high pore pressure. Pressure drop between the reservoir and the wells allow fluids flow through the reservoir to eventually reach production wells, and, for this reason, when there is not sufficient energy to establish fluid movement, a secondary recovery method such as water injection is needed to add energy to the reservoir and thereby maintain its pressure or displace fluids. Before implementing a water injection process, like all oil recovery methods, various scenarios should be evaluated and main parameters identified with the purpose of increasing oil recovery after applying a water injection process.
As the petroleum reserve discovery goes deeper in the offshore oil industry, high pressure reserves are discovered. Those wells will produce at very high initial flowing wellhead pressures (> 10,000 psi) and at much lower flowing wellhead pressures after a period of production. This presents a significant challenge for design and operation of the production system, especially, the subsea production choke, being required to have very low flow coefficient (Cv) in early life to restrict flow, and very high Cv in late life to reduce pressure loss. Initially, the pressure across the choke is required to be 5000 psi or higher. Associated with the high pressure loss across the choke, the Joule-Thompson effect will cause much higher temperatures (up to 30 - 40 °F) at the downstream of the subsea choke compared to non-restricted flow. The elevated temperature challenges the materials of the downstream equipment and the pipelines/risers.
This paper presents an innovative concept ¾ using dual subsea chokes to split the pressure to protect the chokes and improve production operations. The advantages and disadvantages of using dual subsea chokes are presented.
Major High Pressure High Temperature (HPHT) reserves are being developed in the North Sea and the Gulf of Mexico. The learning curve has been very steep on key completion technologies, subsea equipment and installations. The range of pressure and temperature are not well defined as industry consensus. In the UK sector of the North Sea the wells are called HPHT wells with a reservoir pressure (>14,500 psi or 1000 bar) and high temperature (>266°F or 130°C) . In the Gulf of Mexico (GoM), operators are looking at the ultra-high pressure and temperature prospects (>25,000 psi and >450°F) [2, 3]. The current deepest well is completed at 29,860 ft TVD. New discoveries may exceed 30,000 ft. A three-tier classification has been proposed for well completion in the paper :
Fluid characterization regarding sour/sweet service is a major challenge to set the design criterion for well tabular and subsea equipment, including the choke body and trim material selection.
Figure 1 shows the subsea choking requirement on subsea choke to maintain low flowline pressures. In a 10,000 ft water depth, if a well is completed at 30,000 ft TVD, the choking pressure loss is about 5000 psi, the water depth and pipeline pressure loss is about 3500 psi and wellbore pressure loss is about 7,000 psi. The reservoir pressure loss is usually in the range of 500 -1,500 psi. Those numbers are not precise calculation results, instead, only to show the magnitudes of each component in a deepwater HPHT production system.
A reliable subsea adjustable choke is essential to a subsea production system. The critical challenge is trim material and configuration. A historic review for choke development was presented in references [4, 5]. A list of parameters for selecting a subsea production choke has been presented in reference  and being slightly modified and shown as Table 1. The flow characteristics of orifice-type and cage-type subsea chokes have been investigated .
Effective choking is critical to apply HIPP systems to the subsea pipeline [7, 8]. The choke is required to set the pressure at the inlet well below the design pressure to allow for flow transients and to provide sufficient time for HIPPS valve to close in the event of a pressure increase due to blockage.
Recent discoveries of High Pressure High Temperature oil and gas reserves in the Gulf of Mexico and the North Sea presented a significant challenge to subsea production technologies, and especially for the production control. Most significantly, while the pressure differences at early production are estimated to be around 5000 psi or even higher, they are expected to substantially decrease over time. Such anticipated pressure gradient is difficult to manage in a safe and economic manner using currently known technology.
In the last 18 months, within the five Exploitation Integrated Assets in the South Region of PEMEX E&P, a well management program coupled with multidisciplinary teams has been implemented obtaining 24.5 MMSTB of oil and 40.1 Bscf of gas from workover of 372 wells that were shut in or had production problems. With the implementation and surveillance of this program in the field was possible for these assets to increase the production of oil to over 136 MSTB/D and gas to over 257 MMscf/D. These increases in production has made possible to maintain a production near to 500,000 STB/D of oil and 1,360 MMscf/D of gas in this region, offsetting natural production decline and loss of production due to a strong water invasion of wells. A profit-to-investment ratio of 16 has been obtained. Additional hydrocarbon production greater than 111 MSTB/D of oil and 196 MMscf/D of gas have been identified from 353 wells. The successful implementation of this program was based on the application of selected technologies that contributed to the increase of well productivity from the selected fields. This paper presents the applied methodology and the current results obtained from this well management program to optimize the recovery of hydrocarbons of the identified opportunities within these assets units with minimum investments. In addition to the value added of production increase through this well management approach, the following benefits were obtained: learning and applying the team work approach of well management, adaptation to a new cultural change of working as teams to solve difficult problems, training and transfer of diverse technologies, methodologies, and software technologies from the interdisciplinary teams to the technical personnel of PEMEX E&P, and specific well data information certified that can be used to evaluate reservoirs studies.
PEMEX E&P in the South Region covers a surface area of 392,000 of square kilometers. This region has been conformed by five production integral assets including Bellota-Jujo, Cinco-Presidentes, Macuspana, Muspac, and Samaria-Luna as shown in Fig. 1.
The producer reservoirs of these assets consist of Tertiary sandstones and Cretaceous carbonates which are naturally fractured rocks. The fields store all types of petroleum fluids that include dry gas, wet gas, condensate of gas, volatile oil, and black oil, with densities ranging from very heavy oils of 10 oAPI to superior quality oils up to 60 oAPI. However, 97% of the overall oil production in the region is light with densities greater than 30 oAPI.
Hydrocarbon exploitation in the South Region started in April of 1953 with 3,354 STB/D. Peak oil production was achieved in December of 1979 with a production of 1.213 MMSTB/D as shown in the continue line in Fig. 2.
Similarly, maximum natural gas production was reached at the rate of 2,853 MMscf/D in October of 1981 as shown in Fig. 2 as a discontinue line.
The hydrocarbons exploitation history of the South Region can be characterized through six well defined production steps as shown in the top of Fig. 2.
The first production step is defined from 1953 to 1972. This period describes the development and exploitation of the tertiary fields in Cinco Presidentes (Agua Dulce), Bellota-Jujo (Comalcalco), and Macuspana assets (Fig. 1).
The biggest fields in the region were developed in the second step defined from 1972 to 1980. These fields are Sitio Grande and Cactus in Muspac asset, Antonio J. Bermudez complex in the Samaria-Luna asset, and Jujo-Tecominoacan and Cárdenas fields in the Bellota-Jujo asset. As mentioned before, at the end of this step the maximum oil production was reached.
The third production step is defined from 1980 to 1990 where the main fields at the Muspac asset were developed such as Muspac, Chiapas-Copano, Giraldas and Agave. At the same time, Luna-Palapa fields in the Samaria-Luna asset were developed. In this step, on 1981 was recorded the peak of gas production as described before.
In this step, between 1980 and 1984 severe oil production decline occurred estimated at 100,000 STB annually. In November 1984, oil production was recorded at 828,020 STB/D. Starting in January 1985 a oil production decline was observed in the amount of 35,000 STB annually.
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.
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.
Archie's empirical law constitutes the basis of quantitative Petrophysics; however, the physical significance of this law is poorly understood. The issue involves substantial uncertainty in oil in place. Similarly, Carman-Kozeny's (C-K) relation is source of several permeability models. C-K is derived from Poiseuille's equation, applicable in laminar-viscous-flow in straight-uniform non-communicating tubes. Neither C-K nor Poiseuille's formulae consider inertial accelerations, non-Darcy flow, caused by changes in either cross section or flow direction occurring in porous media. Implications include sizeable limitations in permeability modeling.
Suitable hydrodynamic and electrical models can be created using fluid mechanics analytical methods. The models delineate the velocity and electrical potentials, streamlines and controls, represented by C-K and Archie's equations. This approach theoretically verifies both relations and reveals that:
The aim of this work is to show how Archie's law ceases being merely empirical and C-K becomes thorough, thus gaining a full physical conception of their power law behavior. As a result, revised Archie's and C-K relations are proposed for water saturation and permeability computations. Main applications comprise the generation of rock catalogs and synthetic production logs to assist in history matching.
Archie's and C-K are very popular/famous equations. Their usage is widespread despite a common lack of complete comprehension of these relationships.1 Different versions of Archie's and C-K equations exist. Their parameters adopt varied values based on simplifying assumptions, which affect the accuracy of water saturation and permeability estimates.
Both oversimplification and ambiguity, created by the diversity of Archie's and C-K equation forms, will be tackled first. Then, fluid mechanics and electric field similarities and differences will be analyzed, to quantify the influence of both the viscosity of the fluids and the geometry of porous media. This quantification is the main difficulty in permeability and saturation modeling, and in explaining fluid and electric flow. Since the analyses contemplate the connectivity among the different capillary routes, a brief discussion of pipe networks and flow regimes at pore-scale will be included.
Finally, electric and hydraulic models will be conceived to demonstrate amended versions of Archie's and C-K equations. Mathematical amalgamation of these relations will set the foundation of a theory-based permeability/rock type model, which includes the ingredients of dynamic surface area, pore throat/pore body dimensions, electric and hydraulic tortuosities, and fluid distribution. Discussion and validation of all these topics will follow.
This paper clarifies several phenomena: Archie's first equation responds to rock geometry only, because electric flow has no viscosity. Archie's second equation describes the distribution of water in partially saturated pores. Fluid viscosity effects, rock geometry, and various flow regimes simultaneously acting, govern hydraulic flow, hence C-K equation. All three equations relate to a microscopic description of the rock. Their coefficients and variable exponents physically represent tortuosities, which respond to the magnitude of "corner?? angles and reflect the change in direction of the bulk of the flow.
In hydraulic flow, the variable exponent reacts to both viscosity and change in direction. An efficiency multiplier handles the losses due to the changes in cross section of the fluid path, as it is stipulated for classic hydraulic components.
Arguments are presented to prove that resistivity and resistance are not quantitatively interchangeable as Ohm's law suggest. This has profound implications in shaly sand models. Emphasis is put in what the literature clarifies in a subtle manner: in electrostatic charge-free regions, Ohm's law must be complemented by Laplace's differential equation, whenever the shape of the conductors is not straight.
Worldwide there are almost 920,000 producing oil wells, about 87 % of these wells are operated using different artificial lift methods and roughly distributed as: 71 % are producing using beam pumping system, 14 % using electrical submersible pumping (ESP), 8 % using gas lift and 7 % using all other forms of lifting systems.
This study was undertaken using advanced predictive methods, high strength rods, optimum pumping mode, and unit geometry to optimize the performance of beam pumping system for deep high volumes oil wells. Three geometries of different surface pumping units were analyzed and studied including, conventional, Reverse Mark and Mark II units. Each geometry of these three types has been subjected to different design features that affect torque and different linkages affecting its kinematics behavior. The highest strength sucker rod string, beam unit geometry, stroke length, pumping speed and subsurface pump size were varied and analyzed jointly to obtain optimum pumping parameters capable to produce maximum fluid at different well depths. This study considered and applied many variables including; well depths from 1,000 to 15,000 ft, three different rod grades, water cuts from 0.0 to 100 %, different pump sizes from 1.25 to 5.75 in, stroke lengths from 100 to 260-inch, and non-API sucker rod grades.
The results indicated that the lifted liquid volumes and pump seating depths for deep wells can be effectively increased using the beam pumping systems. The surface unit geometry has shown a crucial effect of increasing the produced quantity from deep wells. The study recommended using conventional pump unit for shallow depths up to 8,000 ft. The enhanced geometry pumping units of Mark II and reverse Mark have been proven the superior type for deep high volumes wells because it required the least torque to lift the same quantity from different well depths. The study also presented successful field applications for deep wells producing high volumes.
1. Introduction and Review
Downhole pumps are a common means for enhancing the productivity of a well by reducing the bottom hole pressure. Two types of pumps are used including positive-displacement pumps (which include sucker rod pumps and hydraulic piston pumps) and dynamic displacement pumps (Economides et al, 1993).
Beam pumping system is the first and may be the last artificial lift system. A century ago the most universal mechanism for artificially lifting fluid was the standard Shadoof. The earliest documented walking beam and sucker rod pumping system is described in Egyptian historical writing dated 476 AD2, as shown in Figure 1.
In the past, the ability of beam pumping systems to produce high volumes from deep wells was limited due to two main reasons: (1) the high rod and fluid loads, and (2) the lack of deep understanding of the behavior of complex sucker rod system and the involved nature of the reservoir with its contained fluids and inflow performance.
Nowadays, the existence of the following elements leaded to producing high volumes of production from deep wells: (1) development of relatively long stroke enhanced geometry pumping units with good quality tensile strength sucker rods and more accurate predictive software, (2) accurate on site monitoring and control tools, and (3) pumping using large plungers with high pumping speeds.
One century ago, the system mechanism was upgraded for artificially lifting fluid in an oil well to a standard rigfront. It was a wooden walking beam driving a string of hickory sucker rods, often called "well poles?? as many as ten strokes/minutes and 15-in stroke length with the maximum tensile stress of the rods about 12,800 psi. The bottom hole pump was cast iron or brass with the barrel approximately 1.5-in in diameter and well depth ranged from 500 to 1,000 ft. The torque capacity of the band wheel and flat-belt speed reducer ran only a few thousand inch-pounds, and the unit's structural capacity was from 1,000 to 1,500 lb3.
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.
Seabed logging is an emerging technology that measures subsurface resistivity prior to drilling. The technique has been commercially available for over 5 years, and has been proven to reduce drilling risk in many offshore geologic environments.
Electromagnetic scanning is a new application of this proven technology. Sparse spatial sampling and wide azimuth geometry can be used to apply seabed logging to find and accelerate delivery of new prospects in frontier areas. In this paper, we evaluate the costs and benefits of various geometries and show results from the Campos basin in Brasil.
The traditional approach to frontier exploration is to use seismic data to identify structures that are likely to contain hydrocarbons, and then test the structures through exploration drilling. As exploration is driven to increasingly challenging environments, particularly deep water, this approach involves massive investment and risk to operators.
Over the past 5 years, seabed logging has emerged as a major new tool to reduce drilling risk. The physics underpinning this technology is well known. The electrical resistivity of a formation is determined primarily by the pore fluid. Hydrocarbon charged rocks exhibit significantly higher resistivity than water filled rocks. If we can measure the resistivity, we can infer the pore fluid. This principle has been understood for many years, and has been used for the interpretation of borehole resistivity logs.
In recent years, it has become possible to measure the resistivity of the subsurface prior to drilling a borehole1,2,3. Seabed logging is defined as the use of controlled source electromagnetics (CSEM) for the purpose of finding hydrocarbons. Figure 1 illustrates the technique. A powerful horizontal electric dipole source is towed close to the seabed. This source generates electric and magnetic fields which are perturbed by any buried resistors. Careful measurement and analysis of the resultant fields allows the location of buried
resistors to be estimated. It should be noted that not all buried resistors are hydrocarbon reservoirs, and the technique requires careful co-interpretation with other forms of data, such as seismic, well logs etc.
Figure 2 illustrates the power of combining seabed logging data with traditional seismic data. The red well on the left was drilled based on seismic data alone, but no commercial discovery was made. A subsequent seabed logging survey revealed a major resistive anomaly below the crest of a large adjacent structure, which was poorly imaged on P-wave seismic due to the gas cloud above the prospect4.