Reservoir Simulation Research Papers - Academia.edu (original) (raw)

Reservoir simulations of CO* injection into a water flooded oil reservoir show that significant amounts of oil may be recovered, and a high storage capacity of CO, is obtained also through displacement of water. Simulated storage capacities for CO, injection into an aquifer vary in the range 13-68% pore volume, depending on the prevailing displacement mechanisms.

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- Conservation, Migration, Enhanced Oil Recovery, Reservoir Simulation

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- by Syed Esam Mahmood
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- Segregation, Reservoir Engineering, Enhanced Oil Recovery, Reservoir Simulation

In the ongoing aquifer CO2 disposal project in the Sleipner license (North Sea), underground CO2 is being monitored by time-lapse seismic. The CO2 is being injected close to the base of a high permeable, highly porous sand unit, the Utsira Sand. In an iterative process between seismic surveys and reservoir simulations, a reservoir model featuring the major controlling heterogeneities has been developed. Well-data and seismic data prior to injection shows that the sand is divided by nearly horizontal, discontinuous shales. From the 3-D seismic image after three years of injection, strong reflectors can be interpreted as CO2 accumulations identifying the major shale layers that control the vertical migration of CO2 from the injection point to the top of the formation. By modelling this flow in reservoir simulations, it can be inferred that the CO2 is transported in distinct columns between the shales rather than as dispersed bubbles over a large area. Improvement of the geological mod...

- by Amir Ghaderi
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- Geology, Reservoir Simulation, North Sea

Tracer simulations carried out using the TOUGH2 reservoir simulator are prone to numerical dispersion. This paper describes the development of a separate Lagrange–Galerkin finite-element tracer simulator, used in conjunction with TOUGH2, that introduces minimal numerical dispersion.This approach raises the problem of converting the TOUGH2 flow fields to finite-element format. A new method is presented for carrying out this conversion using

- by Michael O'Sullivan
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- Geology, Geophysics, Finite Element, Reservoir Simulation

i n t e r n a t i o n a l j o u r n a l o f g r e e n h o u s e g a s c o n t r o l 1 ( 2 0 0 7 ) 1 9 8 -2 1 4 Utsira Geologic storage a b s t r a c t At Sleipner, CO 2 is being separated from natural gas and injected into an underground saline aquifer for environmental purposes. Uncertainty in the aquifer temperature leads to uncertainty in the in situ density of CO 2 . In this study, gravity measurements were made over the injection site in 2002 and 2005 on top of 30 concrete benchmarks on the seafloor in order to constrain the in situ CO 2 density. The gravity measurements have a repeatability of 4.3 mGal for 2003 and 3.5 mGal for 2005. The resulting time-lapse uncertainty is 5.3 mGal.

- by Ola Eiken and +1
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- Engineering, Earth Sciences, Reservoir Simulation, Environmental Sciences

A practical pressure transient analysis method is presented for a drawdown test in a well near a constant pressure internal circular boundary. The problem was mathematically posed and solved using the Laplace Transformation with the Laplace solutions . Internal boundaries are viewed as circles with infinite radii and act as a known limiting case for finite radii internal boundaries. The time it takes pressure transient to reach the internal circular boundary and the permeability of the reservoir formation bounded by an internal discontinuity is estimated using generalized type curves. Using a new generalized type curve developed in this investigation, the bounded reservoir permeability and transient time to the internal boundary was determined by generalized semi-log type curve matching without using the usual double straight line technique

- by PEPPLE DANIEL
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- Applied Mathematics, Reservoir Engineering, Heat Transfer, Numerical Analysis

In this reservoir study, two adjacent fault blocks have
been subject to the same initial liquid and subsequent gas
charges, yet fl uid characteristics are different. Wells in each
fault block have a gas-oil contact (GOC) and an oil-water
contact (OWC), thus all depth-dependent in-reservoir fl uid
geodynamic processes are visible within each well. The
two adjacent fault blocks are found to be at different stages
of the same reservoir fl uid geodynamic process yielding a
‘movie’ with two time frames.
Diffusion of gas, from the late gas charge, into the oil
column causes a signifi cant increase of solution gas initially
at/near the GOC. This increase in solution gas causes the
asphaltenes to migrate down in the oil column. Well 1 is in
the middle of this process exhibiting huge disequilibrium
gradients of gas-oil ratio (GOR), saturation pressure and
asphaltenes. In Well 2, the diffusion of gas reached the
base of the column expelling most of the asphaltenes out
of the oil column creating a 10-m tar mat at the base of
the column. In Well 2, the oil is nearly in thermodynamic
equilibrium in contrast to large disequilibrium in Well 1.
Asphaltene extracts of core plugs are consistent with these
fl uid profi les and reinforce conclusions. The disequilibrium
oil column is associated with low vertical permeability
as seen with pressure interference testing indicating
multiple baffl es. In drillstem tests (DSTs), the equilibrated
oil column exhibited 10x greater production than the
disequilibrium oil column. Equilibrated asphaltenes are
associated with good production; here, disequilibrium
asphaltene gradients and poor vertical permeability are
associated with low production due to reservoir baffl ing.

Gas condensate fields are quite lucrative fields because of the highly economic value of condensates. However, the development of these fields is often difficult due to retrograde condensation resulting to condensate banking in the immediate vicinity of the wellbore. In many cases, adequate characterization and prediction of condensate banks are often difficult leading to poor technical decisions in the management of such fields. This study will present a simulation performed with Eclipse300 compositional simulator on a gas condensate reservoir with three case study wells-a gas injector (INJ1) and two producers (PROD1 and PROD2) to predict condensate banking. Rock and fluid properties at laboratory condition were simulated to reservoir conditions and a comparative method of analysis was used to efficiently diagnose the presence of condensate banks in the affected grid-blocks. Relative Permeability to Condensate and gas and saturation curves shows condensate banks region. The result shows that PROD2 was greatly affected by condensate banking while PROD1 remained unaffected during the investigation. Other factors were analyzed and the results reveal that the nature and composition of condensates can significantly affect condensate banking in the immediate vicinity of the wellbore. Also, it was observed that efficient production from condensate reservoir requires the pressure to be kept above dew point pressure so as to minimize the effect and the tendency of retrograde condensation.

- by Mingzhen Wei
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- Chemical Engineering, Enhanced Oil Recovery, Reservoir Simulation

Since the middle of the twentieth century, hydraulic fractures and fractures created due to injection under fracturing conditions have been proven to be effective in increasing the productivity and injectivity factors of wells considerably. In this work, an algorithms for determining the optimum hydraulic fracture dimensions, the growth of induced fractures created due to injection under fracturing conditions and modelling fractures in dynamic reservoir simulators are introduced. Additionally, the optimum dimensionless conductivity is derived to be 1.6363 and is used in addition to practical limitations and economic considerations to determine the optimum hydraulic fracture dimensions result in maximum folds of increase in production. Also in this work, an algorithm adopting Perkins-Kern-Nordgren-α (PKN-α) and Ahmed and Economides notation after Simonson analysis is adopted to determine the dimensions of the induced fractures created due to injection under fracturing conditions. The induced fractures are implemented in reservoir dynamic simulators using gridblocks refinement and properties multiplications to increase net to gross, porosity and permeability to mimic the fracture properties. For two simple box models, only approximately 42% increase in run time due to implementing this algorithm in reservoir dynamic simulator is resulted. Therefore, the algorithm presented provides a good approximation for modelling induced fractures growth with reduced simulation run time and storage capacity compared to three-dimensional fracture models. Also, it provides more accurate results compared to the simple two-dimensional models that assumes fixed fracture height. The advantage of the algorithms presented is they combine the fracturing physics with the reservoir dynamic simulator constraints. Therefore, implementing this work provides robust reserves estimation and forecasts for wells with induced fractures warning of fractures propagation into unintended with relatively fast running simulation models.

- by Khaldoon AlObaidi
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- Modeling and Simulation, Modelling, Hydraulic Fracturing, Reservoir Simulation

Tinaquillo es la ciudad más industrializada del estado Cojedes, Venezuela. Su principal fuente de abastecimiento hídrico es el río Tirgua, el cual surte un acueducto a través de una derivación lateral emplazada en el sector Las Mercedes. Adicionalmente, algunos pozos profundos surten pequeñas comunidades dentro del municipio. Durante la temporada seca, la oferta hídrica global no satisface la demanda hídrica poblacional, por tanto se prevé activar el sistema de embalses Las Delicias-Chirguirera-La Montaña. En este artículo se evalúa la viabilidad técnica de dicha activación.

- by Franklin Paredes-Trejo
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- Watershed Hydrology, Reservoir Simulation

The well placement technology has advanced to a stage where we can explore small tolerance targets such as thin reservoirs. Well placement with geosteering, which is the real time adjustment of the well path based on the geological responses to place and maintain the well within the best part of the reservoir, is the technology that has made this progress possible. Geosteering however can get very complex with the increasing heterogeneities of the formations and there is no fixed methodology to devise a steering strategy in such complex geological settings.

- by Reema Omar
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- Structural Geology, Reservoir Engineering, Reservoir Simulation, Reservoir Geophysics

PEMBAHASAN Simulasi reservoar merupakan usaha untuk menirukan/memodelkan suatu reservoar yang sesungguhnya dengan model matematis sehingga perilaku reservoar di masa yang akan datang dapat diprediksi. Model matematis yang digunakan dalam simulasi reservoar ini adalah persamaan-persamaan finite difference. Persamaan finite difference ini diperoleh dari persamaan diferensial parsial yang telah didiskritisasi dalam bentuk ruang dan waktu, sedangkan persamaan diferensial parsial ini diturunkan dari persamaan Darcy, persamaan keadaan dan persamaan konservasi massa. Diskritisasi dalam bentuk ruang mempunyai arti bahwa reservoar dibagi menjadi ruang-ruang (blok-blok), sedangkan diskritisasi dalam bentuk waktu berarti bahwa perilaku reservoar dibagi dalam setiap selang waktu (time step). Diskritisasi dibuat untuk mempermudah penyelesaian numerik dari suatu simulasi reservoar. Persamaan finite difference ini menggambarkan kinerja aliran fluida dalam media berpori. Hasil simulasi reservoar sebenarnya kurang akurat karena masih mengandung kesalahan-kesalahan. Kesalahan yang utama adalah proses diskritisasi, dimana reservoar dibagi menjadi ruang-ruang dan perilakunya dibagi dalam setiap selang waktu tertentu. Diskritisasi menjadi kesalahan yang utama karena sebenarnya suatu reservoar mempunyai satu persamaan matematis yang berbentuk persamaan differensial parsial. Persamaan diferensial parsial ini sangat sulit dipecahkan secara analitis maka dibuatlah persamaan finite difference yang relatif lebih mudah dipecahkan secara numerik. Kesalahan lainnya antara lain: • Kesalahan bawaan Kesalahan ini dapat terjadi karena kesalahan mengambil data maupun kesalahan memasukkan data dalam simulator

- by Jessica Amanda Putri
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- Reservoir Simulation

Oil in place by the volumetric method is given by: Where: N(t) = oil in place at time t, STB V b = 7758 A h = bulk reservoir volume, bbl 7758 = bbl/acre-ft A = area, acres h = thickness, ft φ(p(t)) = porosity at reservoir pressure p, fraction S w (t) = water saturation at time t, fraction B o (p(t)) = oil formation volume factor at reservoir pressure p, bbl/STB p(t) = reservoir pressure at time t, psia II. Calculating Gas in Place by the Volumetric Method Gas in place by the volumetric method is given by: Where: G(t) = gas in place at time t, SCF V b = 43,560 A h = bulk reservoir volume, ft 3 43,560 = ft 3 /acre-ft A = area, acres h = thickness, ft φ(p(t)) = porosity at reservoir pressure p, fraction S w (t) = water saturation at time t, fraction B g (p(t)) = gas formation volume factor at reservoir pressure p, ft 3 /SCF p(t) = reservoir pressure at time t, psia

- by TIDJANI Fatima Zohra
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- Reservoir Engineering, Reservoir Simulation

The second edition of Gulf publishers best selling book of 2006. This time as Elsevier-Gulf joint publication. Even though this is a basic book with time-honoured appeals, it has been revamped to help out modellers and computer program... more

- by Rafiq Islam
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- Reservoir Engineering, Reservoir Simulation

The recent years have seen the emergence of detailed field data acquisition and efficient modelling tools to characterize reservoirs and model their complex internal structure in a realistic way. This progress led to the detection of multi-scale fractures in most reservoirs, and enabled to interpret unexpected field production features such as early breakthroughs. Therefore, the availability of a workflow and an integrated modelling methodology becomes more and more crucial to take into account the geological information about fractures/faults into the reservoir dynamic simulation process for optimizing field productivity and reserves. This paper reviews and illustrates the overall methodology and the specifically-involved procedures and tools we have gradually built from the experience acquired in various fractured field case studies.

- by Remy Basquet
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- Reservoir Simulation, Abu Dhabi
- by Idoko Job John
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- Reservoir Simulation, Petroleum Engineering

In petroleum exploration and development, one thing of particular interest to the reservoir engineer is accurate reserves estimates for use in the financial reporting to the Securities and Exchange Commission (SEC) (for the USA), Department of Petroleum Resources (DPR) (for Nigeria) and other corporate bodies. An accurate description of the volume of fluid present is very important in quantifying the resources and selection of production techniques, rates and overall management of the reservoir. The information obtained is also the basis for resource development and plan making hence the need for cross examination to mitigate inherent problem resulting from overestimation or under estimation due to the use of inappropriate aquifer models and other inherent source of errors. In this work, oil originally in place and aquifer volumes of reservoirs E-1000X and G-9200Y in the Niger Delta, were estimated using Hurst-van Everdingen-Modified, Fetkovich steady state, Fetkovich semi-steady state and the Carter-Tracy aquifer models by performing a non linear regression of average pressure against cumulative oil production, possible causes for variance in the models also, has been highlighted. What has been presented in this study is not really the first globally, but is, on Niger Delta oil fields; at providing the reservoir engineers and production managers a means of determining an appropriate aquifer model to use when calculating water influx and performing reserve estimation and as such; cannot be said to be conclusive. Consequently, the study recommends that the Hurst-van Everdingen-Modified model should be used and that the model should be compared with the Carter-Tracy model.

- by Wilfred Deigh
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- Reservoir Engineering, Reservoir Simulation

This paper presents techniques for interpretation of Mini-Drill Stem Test (MiniDST) for establishing commingled Absolute Openhole Flow Potential (AOFP) in deep water exploration wells in India. These gas bearing reservoirs are vertically heterogeneous with high permeability. MiniDST's are conducted using the inflatable straddle packer system of wireline formation tester. A MiniDST transient sequence consists of a single or multiple flow periods, induced using a downhole pump, followed by a pressure buildup. The objectives of a MiniDST are sampling, estimation of reservoir properties such as permeability (k), skin(s), radial extrapolated pressure (p*) and estimating AOFP. AOFP is an important gas well flow parameter and is used to determine the commerciality of discovered prospects. We use a two step approach in establishing commingled AOFP of gas wells. First, we conduct a multiple station MiniDST run and interpret the data to estimate reservoir parameters (k, s, and p*). We also compute non-Darcy flow coefficient (D) using Swift & Kiel expression and then use an analytical pseudo-steady state equation to establish single point AOFP for each of the tested zones. Second, we extend routine forward modeling and incorporate features such as scaled permeability data, rock types and hydraulic flow units through interpretation of Nuclear Magnetic Resonance (NMR) and wireline petrophysics, into a model. The model is built in two different ways. One is based on numerical simulator and another based on cumulative permeability-thickness product for the gas bearing zones, using average reservoir pressure and temperature for the whole zone of interest. The success of single well simulation has given us the capability to forecast total AOFP for multiple zones using commingled approach. Furthermore, we also included production tubular and choke in our simulation model for well deliverability estimation. Our technique has resulted in immense saving in rig time and cost since the workflow allowed delivering answers which enabled us to determine AOFP without resorting to conventional four points deliverability testing.

- by Sameer Joshi
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- Reservoir Simulation, Well Testing, Petroleum Engineering

A novel Modified Rachford-Rice equation is developed for three-phase equilibrium calculations in hydrocarbon-water systems, based on the free-water assumption, i.e., the water-rich liquid phase consists of pure water only. In the inner loop of the flash algorithm, the three-phase problem (consisting in a system of two non-linear equations) is replaced by a pseudo-two-phase problem (consisting in a non-linear equation). Unlike previous formulations, the new Modified Rachford-Rice function is guaranteed to monotonically decrease between two adjacent asymptotes. The negative flash concept is used, and a search window is proposed for the vapor fraction. The new free-water flash method proved to be robust, and excellent agreement between full three-phase flash and pseudo-two-phase free-water flash was obtained for various test problems. The proposed method is very useful in compositional reservoir simulation of certain oil recovery methods and in process simulation.

- by Alexandre Lapene
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- Chemical Engineering, Water, Equations of State, Reservoir Simulation

Even though the art of reservoir simulation has evolved through more than four decades, there is still a substantial research activity that aims toward faster, more robust, and more accurate reservoir simulators. Here we attempt to give the reader an introduction to the mathematics and the numerics behind reservoir simulation. We assume that the reader has a basic mathematical background at the undergraduate level and is acquainted with numerical methods, but no prior knowledge of the mathematics or physics that govern the reservoir flow process is needed. To give the reader an intuitive understanding of the equations that model filtration through porous media, we start with incompressible single-phase flow and move step-by-step to the black-oil model and compressible two-phase flow. For each case, we present a basic numerical scheme in detail, before we discuss a few alternative schemes that reflect trends in state-of-the-art reservoir simulation. Two and three-dimensional test cases are presented and discussed. Finally, for the most basic methods we include simple Matlab codes so that the reader can easily implement and become familiar with the basics of reservoir simulation.

- by Knut-Andreas Lie
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- Two Phase Flow, Reservoir Simulation, Numerical Method, Porous Media

This paper describes and gives fundamental steps and procedures in carrying out production optimization and well development

Oil fields offer a significant potential for storing CO 2 and will most likely be the first large scale geological targets for sequestration as the infrastructure, experience and permitting procedures already exist. The problem of co-optimizing oil production and CO 2 storage differs significantly from current gas injection practice due to the cost-benefit imbalance resulting from buying CO 2 for enhanced oil recovery projects. Consequently, operators aim to minimize the amount of CO 2 required to sweep an oil reservoir. For sequestration purposes, where high availability of low cost CO 2 is assumed, the design parameters of enhanced oil recovery processes must be redefined to optimize the amount of CO 2 left in the reservoir at the time of abandonment. To redefine properly the design parameters, thorough insight into the mechanisms controlling the pore scale displacement efficiency and the overall sweep efficiency is essential. We demonstrate by calculation examples the different mechanisms controlling the displacement behavior of CO 2 sequestration schemes, the interaction between flow and phase equilibrium and how proper design of the injection gas composition and well completion are required to co-optimize oil production and CO 2 storage.

EXTERNAL SUPERVISOR DATE 3 I, NWANKWO CHINONSO IFECHUKWU with Matriculation number, UG/08/1123 do hereby declare that this project was fully and dully carried out by me. This is in fulfillment of the requirement for the award of Bachelor of Engineering Degree in the Department of Chemical/Petroleum Engineering, Niger Delta University, Wilberforce Island, Bayelsa State. The materials made use of during this work are adequately cited. _________________ _________________ ________________ Name Signature Date 4 Acknowledgment First and foremost, I thank the Creator of heaven and earth for giving me life to see through today. Only my effort couldn't have made this project work feasible. A lot of contribution by many people and numerous writing by scholars have attributed immensely in the actualizing of this project report. I remain grateful to my parents, Mr. & Mrs. Emmanuel Nwankwo; my Uncle, Mr. James Otiocha, for the numerous article he provided to me on the course of this project work; the head of my department, Dr. (Mrs) Rhoda Gumus; my lecturers, Engr. Peletiri S.P., Dr. Abrakasa, Engr. Clifford, Prof. Ogoni, Prof. D. Appah (my project supervisor) and other lecturers who has imparted knowledge on me and contributed to my success through my years in the university. I specially wish to thank Engr. Amula for his wealth of academic morale and advice which he always impact on me. I will not fail to remember Ani, A graduate of University of Port-Harcourt who gave me assurance that this work can be feasible and also offers a lot of assistance to me; in advice, encouragement and direct help. I specially wish to 5 congratulate all my friends, colleagues and persons who have given me confident and support both in my days in this school and in the completion of this project.

- by Nwankwo Chinonso
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- Reservoir Simulation

En este trabajo se realizó un estudio sobre un caso de campo en pozos fracturados hidráulicamente en yacimientos areno-arcillosos, con una disminución importante en su producción de aceite. En los pozos estudiados se sospechó que la integridad de la fractura y su conductividad estaban seriamente degradadas y se consideró su re-fracturamiento. Se detectaron, sin embargo, otras complejidades geológicas y de fluidos que también contribuyeron a la disminución de la producción. Se discuten los resultados de la aplicación, de una nueva metodología para la selección de estos candidatos, a través del análisis dinámico de la presión transitoria para el caso de una fractura de conductividad finita.
Se proporcionan nuevos resultados calculando los parámetros de presión inicial (pi), permeabilidad (k), daño (s), que se utilizan para el diseño del fracturamiento hidráulico; a través de los métodos de la primera y segunda derivada. La metodología incluyó modelos semi-analíticos y numéricos, que permiten explicar la propagación, cierre y longitud final de la fractura apuntalada y total. Fue necesario considerar estas variables para interpretar la presión transitoria y los parámetros durante el diseño. Para diagnosticar y tener un resultado final del primer fracturamiento, se realizaron las pruebas para el ajuste del modelo de yacimiento (condiciones transitorias y presión de yacimiento actual) y para el ajuste del modelo de frontera (condiciones pseudo-estacionarias, reserva original y remanente asociada al pozo). De acuerdo a resultados de campo, mostrados en la literatura (Wolhart et al., 2000, 2007), (Berumen et al., 2000) (Moos et al. 2000) (Zoback, M.D. 2007) se consideró que la producción puede causar rotación de esfuerzos en el área de influencia del pozo y en consecuencia se genera una nueva orientación en la fractura. Esto se tomó en cuenta para los nuevos diseños. (W. John Lee, & Kuchuk, F.)

- by Miguel Angel Vidal Arango and +1
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- Reservoir Engineering, Productivity, Reservoir Simulation, Well Test Analysis of Naturally Fractured Reservoir

Induced Fractures and Hydraulic Fractures Study

- by Khaldoon AlObaidi
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- Geology, Hydraulic Fracturing, Reservoir Simulation, Production Technology

This paper quantifies the influence of petrophysical and fluid properties on array-induction resistivity measurements acquired in the presence of oil-base mud (OBM) filtrate invasion. To simulate OBM-filtrate invasion, we consider a simple two-component formulation for the oil phase (OBM and reservoir oil) wherein the components are first-contact miscible. Simulations also include the presence of irreducible, capillary-bound, and movable water. The dynamic process of OBM invasion causes the component concentrations to vary with space and time. In addition, the relative mobility of the oil phase varies during the process of invasion given that oil viscosity and oil density are both dependent on component concentrations. This behavior in turn affects the spatial distribution of electrical resistivity and, consequently, the borehole array-induction measurements.

This paper aims to review some of the widely used conventional and other contemporary Inflow & Productivity models that exist for Horizontal wells, and comment on their limitations by drawing on the experiences of other author's critiques... more

- by Krishna Kumar
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- Petrophysics, Petroleum, Reservoir Engineering, Petroleum geology

An offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. The permeability distribution varies across different layers with an overall permeability of 680 mD, and porosity distribution for the reservoir varies 0.21-023. The reservoir thickness also varies up to 50 m thick. This work identifies parameters that will contribute to the impact of water coning by observing the effect of water coning/cresting in horizontal gas wells and predicting the performance of these wells using Petrel simulator. Results have shown that, locating horizontal well in East-west will have early water breakthrough and not recommended due to the impact of edge aquifer and less recovery compared to north-south and original wells orientation (northwest-southeast). Varying height of perforation of the well and standoff between 30 m and 40 m will delay water coning and high recovery with more extended plateau length period. The gas recovery was observed to be low, due to the distribution of permeability layer for the horizontal wells and low productivity index (performance of the well). Rate-dependent skin and mechanical skin evolution in time show that increasing non-Darcy /turbulence factor reduces the performance of the well and decreases gas recovery, the high drawdown tendency is observed before water breakthrough time. Horizontal gas wells have a constant horizontal length of 300 m. Increasing tubing head pressure from 40 bar to 100 bar result to decrease plateau length period of the gas production, low water production rate, and low gas recovery. Varying the kv/kh ratio from 0.1, 0.6 to 1 shows early water breakthrough by 6 months earlier from the base case with 0.1 hence will not delay water coning and the gas recovery is reduced by 5%. There is a stronger of the aquifer from the west side, which is predictable to cause water coning than on the east side. This aquifer impacts the gas recovery reduction by 19 %, with water coning radial extension of 1.7 km and peak water production rate for 16 years. The aquifer influx rate is seen to be increased by 69% when the aquifer volume is double. Therefore, from the results, producing at a high rate that has high recovery before the impact of aquifer or water has occurred to the wells, known as outrunning of the aquifer. To avoid water coning, using advance completion technique such as inflow control devices (ICD), installing a down hole gauge. Also, it is essential not to perforate if well is near to gas water contact, the horizontal wells should be located at maximum distance from gas water contact to maximize gas recovery. Not only that but also use of fully open choke allows much water production rate increase, which leads to water coning.

Géomécanique en simulation de réservoir : méthodologies de couplage et étude d'un cas de terrain -Cette publication traite de la modélisation des effets géomécaniques induits par l'exploitation des réservoirs et de leur influence sur les écoulements de fluide dans les réservoirs. Ces effets géomécaniques peuvent être relativement conséquents dans le cas des réservoirs faiblement consolidés et des réservoirs fracturés. Les principaux mécanismes couplés intervenant lors de la production de ces réservoirs, ainsi que les méthodes permettant de les modéliser, sont présentés. Le comportement géomécanique d'un cas réel est ensuite étudié. Un simulateur couplé -ATH2VIS -est utilisé afin de quantifier les effets géomécaniques induits par l'exploitation d'un réservoir carbonaté fortement hétérogène et compartimenté. Ce simulateur met en oeuvre un couplage explicite et gère les échanges de données entre le simulateur de réservoir ATHOS TM développé à l'IFP et le simulateur de géomécanique VISAGE TM (VIPS Ltd. 2001). Le résultat des simulations couplées indique que la modification de l'équilibre mécanique du milieu se traduit par une localisation de la déformation sur certaines failles en fonction de leur orientation et des variations de pression et de température dans leur voisinage. Il est également observé que seule une partie de la faille atteint le seuil de déformation plastique. Au cours de l'analyse couplée, le tenseur de déformation plastique sur les plans de faille est traduit en variation de la transmissibilité de la faille afin d'améliorer la représentation des écoulements dans le réservoir et de faciliter le calage des historiques de production.

- by P. Longuemare and +1
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- Reservoir Simulation, Case Study
- by Zohreh Movahed
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- Geology, Image Processing, Structural Geology, Research Methodology

Over the last three decades, shale gas reservoirs have emerged as gigantic gas resources. Economic production from shale gas cannot be achieved by natural mechanisms alone; it requires technologies such as hydraulic fracturing in multiple stages along a horizontal wellbore. Developing numerical models for hydraulic fracturing is essential since a successful fracturing job in a shale formation cannot be generalized to another due to different shale characteristics, and restricted access to the field data acquisition. Empirical methods and Linear Elastic Fracture Mechanics (LEFM)-based numerical techniques are still the prevailing design tools in most hydraulic fracture applications though they provide a reasonable prediction only for hard (brittle) rocks. The plastic zone and softening effects at the fracture tip have been neglected in modeling hydraulic fracturing, which results in the prediction of conservative fracture geometry and imprecise fracture pressure. These effects can be identified by the Cohesive Zone Model (CZM) but not by LEFM. Moreover, CZM is able to model fracturing interfaces; for instance, natural fractures, which are mechanically weaker than the adjoining materials. In addition, petrophysical log data has extended the range of ductility in shale layers even though these layers belong to the same shale formation. Brittle shales are more likely to contain more natural fractures while ductile shales act as good seals for the fractured layers. In this work, we modeled multiple-stage fracturing in a quasibrittle shale layer using an improved CZM for porous media besides including the material softening effect. We sought to determine the superiority of CZM compared to LEFM in shales. Also, we investigated various scenarios in number and sequence of fracturing stages for different rock properties. Moreover, we examined the fracture behavior after the fracturing fluid shut-in. We found that the stress shadow effects on induced fractures significantly influenced the characteristics of subsequent induced fractures.

- by Mahdi Haddad and +1
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- Reservoir Engineering, Hydraulic Fracturing, Reservoir Simulation, Petroleum Geomechanics

Flood control operation (FCO) of a reservoir is a complex optimization problem with a large number of constraints. With the rapid development of optimization techniques in recent years, more and more research efforts have been devoted to optimizing FCO problems. However, for solving large-scale reservoir group optimization problem, this is still a challenging task. In this work, a reservoir group FCO model is established with minimum flood volume stored in each reservoir and minimum peak flow of downstream control point during the dispatch process. At the same time, a flood forecast model for FCO of a reservoir group is developed by coupling Yin-Yang firefly algorithm (YYFA) with ε constrained method. As a case study, the proposed model is applied to a three-reservoir flood control system in Luanhe River Basin consisting of reservoirs, river channels, and downstream control points. Results show that optimal operation of three reservoirs systems can efficiently reduce the occupied storage capacity for flood control and flood peaks at downstream control point of the basin. The proposed method can be extended to FCO of other reservoir groups with similar conditions.

Main reason of waterflooding an oil reservoirs is to increase production rate of oil, and ultimately, the recovery efficiency.
In this research project, waterflood mechanism for fractured carbonate oil reservoirs has been studied. As a first part of the project, literature review on theoretical discussions has been done which then followed by practical discussions of simulated model from field case example. Both parts have then been compared and discussed to decide on the accuracy and reliability of the methods used.
According to theoretical study of waterflooding, factors affecting oil recovery and their reliability were discussed in detail. Some of those factors were proven in simulation case study using curves and figures as representatives. Simulation study is based on sixth SPE comparative solution project introduced by A. Firoozabadi and L.K.Thomas in June 1990.
Five cases were presented as simulated results to observe different recoveries of waterflooding fractured carbonates for different cases. In the full-scale reservoir, it was obtained that, capillary continuity gives reduced recovery as agreed with theoretical discussion on waterflooding fractured mixed-wet reservoirs. The recovery displayed an increment in terms of applying dual porosity dual permeability modeling, as compared to dual porosity modeling. An increased recovery was depicted for increased fracture opening and, mainly for presence of gravity forces.
Importance of consistency of simulated results were proved by comparing theoretical studies. Every part will be discussed in detail afterwards

Faults in clastic sequences are often significant barriers to single-phase fluid flow and can act as absolute barriers to the flow of non-wetting phases over geological time. Knowledge of the fault rock flow properties, as well as the width of the fault zone is required in order to conduct fluid flow simulations in faulted reservoirs. In this paper we present an equation for estimating fault zone thickness from fault throw based on outcrop data from Sinai (Knott et al. 1996) and Northumberland. These data show that the throw/thickness relationship is dependent on lithology, and can be related to the clay content of the fault zone. The permeability and threshold pressures of faultrocks are dependent on factors such as the mineralogical composition of the faulted rock, the effective stress conditions and the time-temperature history of the reservoir prior to, during and following deformation. A strong power law relationship is established between threshold pressure and permeability, which is insensitive to the faulting mechanisms. The permeability and the threshold pressures of both the host rocks and the fault rocks can be represented by functions which are dependent on the clay content and the maximum burial depth (i.e. time-temperature history), whereas for the fault rocks the depth (i.e. effective stress conditions) at the time of deformation also needs to be taken into account. The database from which these empirical relationships were derived contains core measurements from faults and their associated host rocks in siliciclastic sequences from the North Sea. Many types of fault rock are contained within the database (disaggregation zones, cataclastic faults, phyllosilicate-framework faults and clay smears) and these have experienced a wide range in their maximum burial depths (2000m-4500m). In reservoir simulation the sealing effect of the faults can be represented as transmissibility modifiers for each grid cell, calculated from knowledge of fault rock permeability, the width of the fault zone, the grid block permeabilities and the geometry of the simulation grid . We have applied the technique to a number of North Sea reservoirs, using the new equation for calculating fault rock permeability. However, even if the new equation produced lower permeabilities than previously published relationships, in all cases the transmissibility modifiers generated by this technique proved consistently too high (1-2 orders of magnitude) in order to produce good history matches. In order to further improve the model, and to get better history match, we think that it is important to include capillary effects, relative transmissibility multipliers, the new equation for calculating fault zone width and to better constrain the clay content of the fault zone. However, better methods are still required for capturing complex fault geometries in the reservoir model. Sperrevik et. al. Empirical estimation of fault rock properties

- by susanne sperrevik
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- Reservoir Simulation, Power Law, Fluid flow, North Sea

The injection of CO2 in exploited natural gas reservoirs as a means to reduce greenhouse gas (GHG) emissions is highly attractive as it takes place in well-known geological structures of proven integrity with respect to gas leakage. The injection of a reactive gas such as CO2 puts emphasis on the possible alteration of reservoir and caprock formations and especially of the wells’ cement sheaths induced by the modification of chemical equilibria. Such studies are important for injectivity assurance, wellbore integrity, and risk assessment required for CO2 sequestration site qualification. Within a R&D project funded by Eni, we set up a numerical model to investigate the rock–cement alterations driven by the injection of CO2 into a depleted sweet natural gas pool. The simulations are performed with the TOUGHREACT simulator (Xu et al. in Comput Geosci 32:145–165, 2006) coupled to the TMGAS EOS module (Battistelli and Marcolini in Int J Greenh Gas Control 3:481–493, 2009) developed for the TOUGH2 family of reservoir simulators (Pruess et al. in TOUGH2 User’s Guide, Version 2.0, 1999). On the basis of field data, the system is considered in isothermal (50°C) and isobaric (128.5 bar) conditions. The effects of the evolving reservoir gas composition are taken into account before, during, and after CO2 injection. Fully water-saturated conditions were assumed for the cement sheath and caprock domains. The gas phase does not flow by advection from the reservoir into the interacting domains so that molecular diffusion in the aqueous phase is the most important process controlling the mass transport occurring in the system under study.

- by claudio geloni
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- Chemical Engineering, Civil Engineering, Applied Mathematics, Carbon Dioxide

After conventional waterflooding processes the residual oil in the reservoir remains as a discontinuous phase in the form of oil drops trapped by capillary forces and is likely to be around 70% of the original oil in place (OOIP). The EOR method so-called Alkaline-Surfactant-Polymer (ASP) flooding has been proved to be effective in reducing the oil residual saturation in laboratory experiments and field projects through reduction of interfacial tension and mobility ratio between oil and water phases.

- by Salvador Pintos and +1
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- Modeling, Performance, Sensitivity Analysis, Enhanced Oil Recovery
- by Henk Pagnier and +1
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- Renewable Energy, Energy Consumption, Fuel Cell, Reservoir Simulation

Efficiency for Recovering Oil in Heterogeneous Reservoirs." This research improved our knowledge and understanding of CO 2 flooding and included work in the areas of injectivity and mobility control. Chapter 1 summarizes a survey performed for all the CO 2 injection projects in the Permian Basin. Chapter 2 covers CO 2 -brine-reservoir rock interactions that were studied to better understand injectivity implications. Chapter 3 summarizes work performed to determine possible injectivity and productivity reduction due to high flow rate in near-wellbore regions, and Chapter 4 summarizes work in the areas of foam stability, interfacial tension, surfactant adsorption and desorption, and mobility control. Chapter 5 lists the papers, reports, workshops, and presentations produced as a result of the research work under this contract.

- by Zhengwen Zeng
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- Chemistry, Fluid Mechanics, Rock Mechanics, High Pressure

The limitation of Steam Injection to depths (usually not more than 5000-ft) has been a subject of concern in the application of Steam Injection for heavy and extra heavy oil recovery. This is usually as a result of the complex mechanism of heat loses occurring in the wellbore and consequently the heat loss distribution in the reservoir. A conventional approach to the optimization of steam injection has been based on isolated analysis of the well system aimed at maintaining adequate steam quality at the sandface at optimal injection rate, pressure, temperature and overall heat transfer coefficient. This often result to total neglect of the effect of the interaction between the well system and the reservoir system in the Model results. This research work therefore presents an integrated approach in the modelling of steam injection project that incorporates both the well system and the reservoir system. In this study, a three (3) case-study wells were analyzed which are located at INJ1 (1, 1), PROD1 (5, 5) and PROD2 (9, 1) respectively. The results of the findings reveals that the conventional practice of maintaining sufficient SQ at the sandface is not the last optimization strategy in real field scenario. This is because the efficiency of the heavy oil displacement by the steam is a co-function of the effective SQ at the sandface, the FHLR/FHLT and the relative distance of the injector(s) from the producer(s) which are characterized by the thermal properties of the reservoirs. As part of the objectives of this study, a novel numerical approach using PROSPER wellbore simulator is presented for analysing the impact of reservoir back pressure on the estimated SQ. The results as presented in the work shows that wrong estimations of downhole SQ can result from the total neglect of Reservoir Pressure especially in relatively deeper wells.

- by Ifeanyi S Nwankwo
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- Reservoir Engineering, Reservoir Simulation

Screening and evaluation of CO2 storage CO2 storage in geological strata Saline aquifer CO2 storage Geological modeling Site characterization Reservoir simulation CO2 injectivity and storage capacity assessment a b s t r a c t This work is a preliminary screening and evaluation of one of the most promising geological structures for CO 2 storage in the Czech Republic, namely the deep saline aquifers of the Central Bohemian Permian-Carboniferous Basin. Archived and new mineralogical, petrophysical, lithological, geochemical, sequence-stratigraphic, thermal history, core analyses, hydrogeological testing, and seismic data for both the reservoir formation and seal rocks were used to build an initial static geological model of the Central Bohemian Basin. Using this static geological model, a sector of the Basin was identified as meeting the basic geological requirements for CO 2 storage; a preliminary reservoir model of this sector was created and used to perform several simulation runs to further evaluate the suitability and potential of the selected formation for storing captured CO 2 from industrial emissions.

- by R. Berenblyum and +1
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- Engineering, Earth Sciences, Modeling and Simulation, Reservoir Simulation

In this work, we modeled double- and triple-cluster 3D hydraulic fracturing in a single-layer, quasi-brittle shale formation using planar CZM and XFEM-based CZM including slit flow and poro-elasticity for fracture and matrix spaces, respectively, in Abaqus. Our fully-coupled pore pressure-stress Geo-mechanics model includes leak-off as a continuum-based fluid flow component coupled with the other unknowns in the problem. Having compared the triple-cluster fracturing results from planar CZM with those from XFEM-based CZM, we found that the stress shadowing effect of multiple hydraulic fractures on each other can cause these fractures to rationally propagate out of plane; this also demonstrates the advantages of the second method compared to the first one. We investigated the effect of this arbitrary propagation direction on not only the fractures’ length, aperture, and the required injection pressure, but also fractures’ connection to the wellbore. Depending on the spacing and the number of clusters per stage, this connection can be gradually disrupted with time due to the near-wellbore fracture closure which may embed proppant particles on the fracture wall, or screen out the fracture at early stimulation times. Comparing all studied cases, we concluded that the double-cluster, simultaneous fracturing with 100-ft spacing provides the most viable fracture set for long-term production.

- by Mahdi Haddad
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- Numerical Simulations, Rock Mechanics, Geomechanics, Reservoir Engineering

Este artículo compara los resultados de un proceso de inyección convencional de agua versus inyección cíclica en un yacimiento de crudos pesados de 15 °API de la Formación Oficina en el campo San Cristóbal. La inyección cíclica de agua es una técnica de recuperación secundaria dividida en dos periodos: Inyección y Cierre de pozos inyectores, en este último ocurre despresurización y redistribución de fluidos y basados en la histéresis de las fuerzas capilares generadas en el sistema roca fluido en tal sentido algunas moléculas de petróleo se desplazan desde zonas de bajas propiedades hacia zonas de mejores características petrofísicas y en consecuencia hacia pozos productores, los cuales siempre se mantienen activos, permitiendo mayor recobro de petróleo y reducción del agua producida durante el medio ciclo de cierre de pozos inyectores. Ello se obtuvo a través de un estudio de simulación 3D Black Oil (Eclipse 100) activando la opción Histéresis, donde se calibró el modelo de roca fluido usando las curvas de drenaje e imbibición de la Presión Capilar obtenidas de análisis especiales de un núcleo del yacimiento en estudio, a fin de comparar ambos procesos.

- by Elias R Acosta and +1
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- Reservoir Engineering, Modeling and Simulation, Reservoir Characterization, Reservoir Simulation
- by Ayodele O L A D A P O Awe
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- Reservoir Simulation

This study uses a multidisciplinary approach
to simulate the spatial and temporal patterns of hydrodynamics
and water quality in a thermally stratified
reservoir in the southern side of the Mediterranean Sea
in response to water withdrawal elevation using the 2D
water quality and laterally averaged hydrodynamic
model CE-QUAL-W2. The withdrawal elevation controls
largely the transfer of heat and constituents in the
dam in particular during thermal stratification. Fifteen
scenarios of withdrawal elevation are possible. To identify
the most effective scenarios, a hierarchical clustering
technique was performed and only four scenarios
were clustered. Deep withdrawals deepen the hypoxia,
increase the thickness of the metalimnion, and weaken
the stratification stability, which facilitate the vertical
transfer of heat and dissolved oxygen mainly. Surface
withdrawals, however, shrink the metalimnion and tend
to strengthen the stratification, resulting in less transfer
of matter from the epilimnion to the hypolimnion. Most
of the bottom sediment is overlaid by the hypolimnion.
The oxygen depletes significantly and waters become
anoxic at a few meters depth. For all scenarios, the
reservoir experiences a summer hypolimnetic anoxia,
which lasts from 42 to 80 days and seems to decrease
as withdrawal elevation increases. At the end of stratification,
waters below the withdrawal elevation showed a
noticeable release of iron, nutrients, and suspended sediments
that increases with depth and near-bottom turbulence.
Attention should be drawn to shallower withdrawals
because they accumulate nutrients and silts
continuously in the reservoir, which may deteriorate
water quality. Based on these results, a withdrawal elevation
rule is presented. This rule may be adjusted to
optimize water withdrawal elevation for dams in the
region with similar geometry.

Objective/Scope: Integrated asset modeling (IAM) offers the oil industry several benefits. The next-generation reservoir simulators help achieve faster runtimes, insight into interaction between various components of a development, and can be used as an effective tool in detecting bottlenecks in a production system as well as a constant and more effective communication tool between various departments. IAM provides significant opportunities for optimization of very large or complex infrastructures and life-of-field analysis of production optimization scenarios.Simultaneous modeling of surface and subsurface components helps reduce time and enhances efficiency during the decision-making process which eliminates the requirement for tedious, time-consuming work and iterations between separate solutions of reservoir and surface networks. Beyond this convenience, this technology makes it possible to reach more robust results more quickly using surface-subsurface coupling. The objective of this study is to outline the advantages and the challenges in using next-generation simulators on simulation of multiple reservoirs in integrated asset management. Methods/Processes: Simultaneous simulation of multiple reservoirs adds another dimension of complexity to the process of integrated asset modeling. Several sub-reservoir models can be simulated simultaneously in large fields comprising sub-reservoirs with complex surface systems, which could otherwise become very tedious to handle. In this study, a next-generation reservoir simulator is coupled with an optimization and uncertainty tool that is used to optimize the net present value of the entire asset. Several constraints and bottlenecks in such a large system exist, all connected to one another. IAM proves useful in debottlenecking to increase efficiency of the thorough system. The strengths and difficulties associated with simultaneous simulation and optimization of multiple reservoirs are compared to the more conventional way of simulating the assets separately, thus illustrating the benefits of using next-generation reservoir simulators during optimization of multiple reservoirs. Results/Observations: The results show that simultaneous solution of the surface-subsurface coupling gives significantly faster results than that of a system that consists of separate solution of surface and subsurface. The speed difference becomes more significant when the number of reservoirs simulated is more than one. This study outlines the workflow in setting up the model, the CPU time for each component of the simulation, the explanation of each important item in this process to illustrate the

- by Cenk Temizel and +1
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- Reservoir Simulation