This work presents new Modified Black Oil (MBO) PVT properties (Rs, Rv, Bo, and Bg) correlations for volatile oil and gas condensate reservoir fluids. These new correlations do not require the use of fluid samples or EOS calculations. The correlations have the advantage of taking into consideration the effect of surface separator configuration (two and three stages) and conditions (separators pressures and temperatures).
The correlations were developed using fourteen actual reservoir fluid samples (7 gas condensates, 3 near critical fluids, and 4 volatile oils) spanning a wide range of fluid behavior and characteristics. Whitson and Torp method was used to generate Modified Black Oil (MBO) PVT properties that were used as a data set for correlations development.
The MBO PVT properties data points were generated by extracting the PVT properties of each sample using commercial PVT software program at twelve different separator conditions spanning a wide range of surface separator configuration and conditions to generate twelve curves for each sample. A statistical approach using a statistical software program (SPSS) was used to develop the new correlations models.
The results of the new models show reasonable agreement between Modified Black Oil PVT properties generated from the new correlations and the MBO properties extracted using Whitson and Torp method. The average absolute error in the correlations was 8.5% for volatile oils and 17.5% for gas condensates.
These correlations were also validated by comparing the results of modified black oil simulation using MBO PVT properties generated from these correlations to the results of full equation of state (EOS) compositional simulation. Also, the generalized material balance equation (GMBE) was used to calculate the initial oil/gas in place (IOIP/GIIP) for many simulated cases using PVT data generated from the new correlations and data generated from EOS models. The advantage of the new correlations comes from being the first in the industry (to the best of our knowledge) that explicitly take into consideration the effects of surface separators configurations (two or three stages) and conditions. Also, all input parameters in the correlations are readily available from field production data. These correlations do not require elaborate calculation procedures or PVT reports.
Issran field is located 200 km east of Cairo-Egypt, producing from fractured dolomite reservoir 8-12 API oil gravity. The reservoir depth ranges from 1000-2000 ft, with BHP 300-500 psi and BHT of 120-200 F. The heavy oil viscosity is 4000 cp at standard conditions and the reservoir rock is oil wet with high H2S content. The high viscosity and low mobility of the Issran field heavy oil in contrast with the strong mobility and low viscosity of the formation water had extended the problem to a severe decline in hydro carbon production.
In an attempt to enhance the production, Steam injection had been deployed in the field to reduce the oil viscosity and hence enhance the mobility of the extra heavy oil. Enhancement in production has dramatically increased after implementing a new technique combining the Steam Injection with the Matrix Stimulation Engineering Utilizing the Fiber Optics Telemetry Enabled Coiled Tubing.
As the first time in the East Africa and East Mediterranean countries, the new technology deployed (Fiber Optics Telemetry Enabled Coiled Tubing) has provided a new dimension to the heavy oil thermal recovery by supplying a full Distributed Temperature Survey (DTS). Real time interpretation of the DTS data enabled the real time decision making during the Matrix stimulation treatment based on the actual downhole parameters. It also provided valuable data regarding mapping of the downhole steam injection utilizing coiled Tubing.
This paper assesses the effect of using the new technology in Coiled Tubing services utilizing the DTS Measurements during Matrix Stimulation Treatment in different wells. It analyses the Successful production enhancement that provided a new dimension to the extra heavy oil enhanced recovery efficiency. It also quantifies the economical added value resulting from the usage of DTS data in respect to conventional matrix stimulation with conventional Coiled Tubing.
Nanotechnology has become the buzz word of the decade! The precise manipulation and control of matter at dimensions of (1-100) nanometers have revolutionized many industries including the Oil and Gas industry. Its broad impact on more than one discipline is making it of increasing interest to concerned parties.
The Nanotechnology applications have pierced through different Petroleum disciplines from Exploration, to Reservoir, Drilling, Completion, Production and Processing & Refinery. For instance, Nano-sensors have been developed rapidly to enhance the resolution of the subsurface imaging leading to advanced field characterization techniques. Nanotechnology also strikes the stage of production enormously to enhance the oil recovery via molecular modification and manipulate the interfacial characteristics. Moreover, in a very similar fashion, it provides novel approaches to improved post production processes.
Only very few publications were able to report the latest accomplishments in different Petroleum Engineering domains. This paper provides an overview of the latest Nano-technological solutions in the O&G industry and covers the recent research developments that have been carried out around the world and paves the way for many researchers and organizations who are interested in the integration of these technological advancements, to discover the challenges and the revolution that Nanotechnology is about to bring to O&G Industry in Egypt.
Egypt's domestic demand for oil is increasing rapidly. Oil consumption has grown by more than 30% in the past ten years. Also, the hydrocarbon reserves in Egypt have witnessed an average increase of 5%/year over the past seven years, while the average recovery factor is still stuck at the 35%. Nanotechnology holds the key solution to this local production challenge as it helps increase the recovered Oil and decrease the cost of production by eliminating problems that occur throughout the field development operations.
Nanotechnology is the use of very small pieces of material, at dimensions between approximately 1 and 100 nanometers, by themselves or their manipulation to create new large scale materials, where unique phenomena enable novel applications.
In simple terms, Nanotechnology is science, engineering, and technology conducted at the Nano-scale. Nanotechnology draws its name from the prefix "nano".
A nanometer is one-billionth of a meter- a distance equal to two to twenty atoms (depending on what type of atom) laid down next to each other.
Thermal oil recovery methods have been widely used not only in heavy oil reservoirs, but also in light oil reservoir with Waterflooding to improve oil recovery. The Steamflooding could be considered as an effective way to enhance the oil displacement especially in heterogeneous reservoirs The field, of 58-years of production history, is located in South of Iraq. It has 40 producing wells. There was an infinite active aquifer located at the east and west flanks. The strength of this aquifer from the west flank is much larger than its in the east flank because the reservoir permeability at the eastern boundaries is lower than as at the western one for all the layers; therefore, Twenty injection wells were drilled at the east flank to maintain the aquifer water approaching to the reservoir. The average surface area for this reservoir is 142 km2 and average formation depth of 10350 ft subsea with a maximum vertical oil column of 350 ft. Average porosity is 21%. The oil is 34°API with an average initial bubble point pressure of 2660 psia. Current reservoir pressure is approximately 4200 psia and the reservoir temperature is 210°F. In this study, a thermodynamic reservoir simulation has been adopted to investigate the competence of Steamflooding to improve oil recovery.
The objective of this work was to examine the feasibility of steam-injection processes, so a thermodynamical reservoir model (CMG-STARS) has been applied to demonstrate the effect of using steam injection as a heating agent to increase the sweep efficiency in this heterogeneous formation. The twenty injection wells have been converted to steam injection for twelve future prediction years. The process has demonstrated a considerable increase of the cumulative oil production. This result has been compared with the base scenario of water injection at the same injection rates of 10,000 STB/DAY per well. The water injection scenario has been done by CMG-IMEX. This incremental has been proved over most of the production wells that have distributed among the reservoir by showing a significant difference between the two cases.
Thermal oil recovery has been widely used in heavy oil reservoirs to enhance/improve oil recovery because of it's ability to positively change the reservoir and fluid properties for more efficient production. Once the steam is injected to the reservoir, it leads to the reduction of oil viscosity and enhance the oil displacement towards the production wells despite the heat loss to the surroundings below and above the formation. The remaining amounts of heat lead to oil mobilization by reduction of its viscosity (1). Since the viscosity is highly sensitive to the temperature, it is reduced a lot due to the temperature (2). Moreover, the steam flooding causes gradually decline in wettability, interfacial tension leading to the enhance oil displacement and sweep efficiency(16). The distribution of the remaining heat into the reservoir depends on the reservoir properties such as permeability and thickness in addition to the reservoir temperature, steam quality, thermal conductivity, and volumetric heat capacity especially in multilayered reservoirs (1). Also, the steam flooding efficiency depends on the oil saturation values. The efficiency of displacing and production performance increases as the oil saturation increases (2). The conduction phenomenon causes the oil production to the surface. However, the convection leads to oil displaced in the steam zone. The steam injection rate per the entire reservoir in heavy oil reservoirs depends on the reservoir thickness, permeability, and well spacing and it ranges from 100-120 t/d per injector (2).
Facilities sand management is tasked with the goal of ensuring sustained hydrocarbon production when particulate solids (i.e. sand or proppant) are present in well fluids, while minimizing the impact of these produced solids on surface equipment. Particle size and total concentration of formation sand or proppant determines their net effect on production and the resulting operability of surface facilities. Conventional sand management control focuses on sand exclusion from the wellbore, either by production limits or completion design. Completions may adversely affect inflow due to skin buildup and both controls impede maximum hydrocarbon production. Alternatively, co-production of fluids and solids, with subsequent sand handling at surface facilities, is an inclusion paradigm that allows sustained hydrocarbon production. Produced solids are removed at the wellhead upstream of the choke using fit-for-purpose equipment. This methodology allows for increased or recovered hydrocarbon production, while their removal upstream of the choke protects facilities operations.
A description of the design, performance, operation, and effect on production rate is provided for sand inclusive production through application examples in the Caspian Sea, Indonesia, and South China Sea. Specific reference is given towards wellhead desanding, which forms the greater part of this approach, and has expanded from the first field installation in 1995 in the UK to every major oilfield producing region. Implementation of dedicated facilities sand management technology has resulted in increased hydrocarbon production from sand producing wells, extension of well life on marginal fields, and re-start of shut in wells.
The first industry-wide workshop to address solids handling from downhole generation to topsides disposal inclusive was held by the SPE Gulf Coast Section in April, 2002 in Houston, TX. This workshop was entitled Facilities Sand Management: Getting the Beach out of Production. This workshop hosted speakers to discuss sub-surface sand management, sand monitoring & measurement, flow-line erosion, facilities design, separation, solids cleaning, disposal, and slurry injection. Attendee response showed that the leading sand handling needs were subsea separation and disposal, subsurface-surface integration, and increasing the robustness of surface facilities to handle sand production.
Several production companies have started to integrate facilities sand management into their sand control portfolio. Equal merit is given to sand separation at the surface facilities and completion technologies to determine which approach provides sustained hydrocarbon production. Gravel pack and screen completions have a well-established installation and operating base and form the majority of conventional sand control. While controlling sand production in numerous wells, these techniques may still pass sand of <50-125 µm diameter under normal operating conditions, and this sand interferes with facilities operations. In the case of a completion failure, the sand amount and particle size may increase rapidly leading to production restrictions or damaged equipment.
The necessity for a technology that could protect surface facilities equipment (i.e., chokes, flow lines, pumps, separators, valves, etc.) in cases of completion failure, open hole completion, or rapid unplanned sand production led to the development of the multiphase desander for solids removal at the wellhead. Since the implementation of this technology 18 years ago, the wellhead desander has found repeated use as a service tool for the collection of solids during workover or well test operations and as a permanent unit operation to protect surface facilities equipment. Implementation of fit-for-purpose sand handling technology into surface facilities has enabled sustained operations in cases where previous actions were to shut in wells, limit hydrocarbon production, or suffer lengthy and costly maintenance outages.
Shape Factor and drainage area in hydrocarbon reservoir are of the necessary and influencing factors on evaluation and optimization of drilling operation in oil fields. There are numerous methods to calculate the reservoir average pressure in conventional and sandstone reservoirs in that shape and drainage area of the reservoir are of important variables. On the other hand, these relations especially set for sandstone reservoirs and have limited usage in natural fracture reservoirs. This research demonstrates an approach to figure out shape factor and drainage area of wells in carbonated and naturally fractured reservoirs in all pressure and fluidity conditions. To assess this goal, results of well testing are carried out both for development of inflow performance curve and finding the drainage area. To make sure about the validity and preciseness of this method, it was investigated against the data from a well in a natural fracture field and the results were compared with those of other methods. Results dictated that the new approach can provide us with more precise and correct routes for the shape of the well in naturally fractured reservoirs. The suggested approach in this research needs production test data that has been optimized by well testing data for naturally fractured reservoirs. Additionally, this approach implemented to the draw down test and Tiab direct technique which is related to Warren and Root solution. What's more, this approach is reliable for all vertical wells in naturally fractured reservoirs (NFRs) with accessible production test data and well testing.
Esmersoy, C. (Schlumberger) | Ramirex, A. (Schlumberger) | Hannan, A. (Schlumberger) | Lu, L. (Schlumberger) | Teebenny, S. (Schlumberger) | Yang, Y. (Schlumberger) | Sayers, C. M. (Schlumberger) | Parekh, C. (Schlumberger) | Woodward, M. (Schlumberger) | Osypov, K. (Schlumberger) | Yang, S. (Schlumberger) | Lui, Y (Schlumberger) | Shih, C. (Schlumberger) | Hawthorn, A. (Schlumberger) | Cunnell, C. (Schlumberger) | Shady, E. (Schlumberger) | Zarhidze, A. (Schlumberger) | Shabraw, A. (Schlumberger) | Nessim, M (Schlumberger)
Seismic provides critical information for drilling, such as 3D structural images showing geological targets or hazards and formation properties relevant to drilling such as pore pressure. However, pre-drill estimates of formation pressures and structural depth images typically have large uncertainties. These uncertainties present drilling risks and could increase the cost of wells in the deepwater and other drilling environments. We present a new method that reduces the uncertainty up to large distances ahead of the bit by optimally integrating existing seismic data with new information acquired in real-time from the well being drilled.
Often the pre-drill seismic earth model remains mostly unchanged during drilling even though real-time LWD data contain significant new information about the formations being drilled. Real-time checkshot measurements provide constraints for the velocity model, real-time logs reveal formation tops, and other while-drilling information such as pressure measurements, mud weights, tests, and drilling events can be used to calibrate the earth model.
Recent advances in acquisition, processing, and integrated earth model building technologies have made this type of utilization of seismic and while-drilling well data to provide results in time for drilling decision making a reality. Results of two field tests are presented. First field work shows the ability of the technique to image a fault accurately in 3D space. The second field work demonstrates the ability to predict pore pressures up to 3000 ft ahead of the bit. Predicted pore pressures were within 0.25 ppg of the actual measured formation pressures.
Seismic is one of the key inputs to drilling planning and execution. Pre-drill planning of a well is made using the seismic depth image and estimated properties important for drilling such as pore pressure, fracture gradient, geomechanical properties etc. We will call this the earth model. The motivation for our work is that this model is not unique. There are multiple models that will fit the same surface seismic data. There is no unique velocity model, pore pressure estimate, and structural image. We call this the seismic uncertainty and this is the cause of many risks encountered during drilling. If we reduce this uncertainty we also reduce the risks.
The successful recovery of hydrocarbons from shales is dependent on physical rock properties such as lamination, brittleness and the presence of natural fractures, as well as chemo-physical properties such as absorption and adsorption. The key parameters defining the hydrocarbon potential of shales are the mineralogy, organic carbon content (TOC) and burial history. These parameters are commonly derived by conventional and special core analysis of SWCs or cores.
This study highlights that most of the analyses and techniques used to determine the hydrocarbon potential of shales can also be performed on cuttings material with a high degree of confidence. The usage of cutting material has significant advantages with respect to sample availability, sample coverage and acquisition costs. Accurate depth allocation of cuttings is problematic but, by careful reference of the measured mineralogical and textural features to the available mudlog and wireline data, the effects can be minimised.
As part of a research project, SGS analysed the mineralogical and lithological composition of 80 cuttings samples, from various wells in the Radioactive Silurian Shale (drilled a Palaezoic Basin, SW of Algeria) by QEMSCAN. In addition, the geochemistry and maturity parameters were determined by Leco (TOC) and RockEval (S1-S3) methods. Furthermore high resolution 3D computer tomography scans (CT) were performed in order to analyse the cutting material for lamination and micro-fractures. The compilation and interpretation of the mineralogical, lithological and geochemical data indicate significant vertical and lateral heterogeneities, probably induced by local facies changes, which possibly lead to strong variances in the shale gas potential.
The properties of the Silurian hot shale samples were compared with QEMSCAN results of shale samples from Canada, UK, published data from the US gas shales and source rocks from Netherlands and Sweden. Based on the comparison, a distinct trend could be established, indicating significant differences in mineral composition between producing gas shales and other more "conventional?? gas source rocks.
Lautenschlager, Carlos Emmanuel Ribeiro (ATHENA / GTEP / PUC-Rio) | Righetto, Guilherme Lima (ATHENA / GTEP / PUC-Rio) | Inoue, Nelson (ATHENA / GTEP / PUC-Rio) | da Fontoura, Sergio Augusto Barreto (ATHENA / GTEP / PUC-Rio)
This paper deals with the implementation and validation of a new hydromechanical partial coupling methodology conducted between two commercial simulators of flow and stress. Such configuration is based on a coupling methodology developed by the Computational Geomechanics Group - ATHENA/GTEP - PUC-Rio, based on the consistent inclusion of terms in flow equation in order to approach the results of fully-coupled simulations. The IMEX® flow simulator was included in the workflow of the coupling code in order to widen the application scope of the methodology developed. To include the new option of flow simulator was required some implementation effort together with validation through simplified models. The algorithms developed to guide the programming were defined after detailed study of numerical and computational functioning of the flow software. The results obtained with the new simulator were compared with the pre-existing configuration (ECLIPSE flow simulator), considering one and two way partial coupling and fully coupled models. In the comparison scenarios set out to validate the implementation, it was evaluated changes of average pore pressure in the reservoir, compaction and subsidence, as well pore pressure variations. Comparisons with the results of pre-existing configuration and the full-coupling scheme demonstrated the success of the developed algorithm. The exchange of coupling parameters between simulators, in the new configuration, has been implemented effectively. Parametric studies of the variables also demonstrated the quality of the new configuration coupling. The rigorous choice of exchange parameters between flow and stress simulators is crucial for obtaining reliable results.
Reservoir production causes changes in the stresses and strains within the reservoir and surrounding rocks. Such changes give rise to the so-called geomechanical effects, namely the effects observed in the system due to the change in pore pressure, characteristic of the extraction and injection of fluids in porous media. In a recent paper, Herwanger & Koutsabeloulis (2011) illustrate some of these effects: subsidence of the surface or seafloor, slipping among stratigraphic planes, reactivation of faults, loss of seal integrity and compaction of the reservoir.
The numerical analyses that consider the geomechanical effects should consider the phenomena in a coupled way. According to Settari & Vikram (2008), coupled problems in geomechanics must take into account the interrelationship of hydraulic, thermal and mechanical variables in the solution of differential equations involved in each particular problem. In general, the mechanical problem is usually addressed by the finite element method and the flow problem by the finite difference method.
The conventional reservoir simulation solves the hydraulic problem involving flow of oil, gas and water through a porous medium. In these simulations, the variation of the pore volume is determined based only in the changes of pore pressure due to the activity of production and injection, and a predefined value of rock compressibility. According to Inoue & Fontoura (2009a), in this type of simulation the total stresses are held constant, and there is no compatibility of displacements between the boundaries of the reservoir and the surrounding rocks: overburden, sideburden and underburden. In fact, what is observed in a field development is the variation of fluid pressure that results in variation of the rock stress state. These variations, in turn, cause changes in porosity, which is reflected in the pressure field. This process of interaction between phenomena is what characterizes the nature of the coupled problems in reservoir engineering. Inoue & Fontoura (2009b) state that in the conventional reservoir simulation - where only the mass balance equations, equations of state and Darcy's law are considered - the change in porosity is dependent only on the variation of the pore pressure and rock compressibility.
With growing global energy demand and depleting reserves, oil well stimulation has become more important. In all of these reservoirs, formation damage is a headache problem which needs to be treated. One of the proposed techniques is to bypass the damaged zone. Radial drilling can provide a solution with lowest costs than the others.
Radial drilling technique utilizes hydraulic energy to create several lateral holes in different directions and levels with several lengths. These lateral holes are made by milling the casing with small bit then by extending these holes laterally using high pressure hydraulic jetting.
The current paper presents a very good analysis and an evaluation of the radial drilling techniques that have been made in one of the Egyptian oil field, and presents screening criteria about the optimum parameters for performing these techniques. A number of pilot tests was performed and analyzed in Egypt in Belayim oil field. Radial drilling performed only on three wells in Egypt; the results obtained from these wells are monitored and analyzed. The reservoir depth varies from 2172 meter to 2481 meter. The first well was laterally drilled with 50 m long by seven laterals and the angle between each two is 90 degrees. The second well was laterally drilled with 50 and 90 m long by 6 laterals in two different levels. The third well was radially drilled by 4 laterals of 50 m long.
From the production point of view, the first well was improved by more than 12.5% increase in production, and the second shows an improvement by about 47% increase. The third well shows an improvement by about 12.5 % but for short period. Several experiences have been learned and registered from drilling these 17 laterals which will help generally for the future radial drilling operational around the world.