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...

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

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

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.

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.

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.

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.

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

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

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 users so that they can save years of man-hours by avoiding the old-school approach.

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.

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.

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.

Differential Liberation (DL) test results, one of the standard experiments performed by Pressure-Volume-Temperature (PVT) laboratories on reservoir fluid samples (black oil) are presented. The laboratory DL test data was simulated using Peng-Robinson Equation of State on HYSYS. The simulated results were compared graphically and statistically to the experimental data in terms of oil formation volume factor (FVF), solution gas-oil ratio (GOR), liberated GOR, gas compressibility factor (z-factor), and gas composition, with respect to pressure, respectively. The simulation result exhibited similar trends to the experimental data in terms of oil FVF, oil liberate GOR, oil solution GOR, and gas Z-Factor. The bubble point pressure from the experimental result is 3734 psig, while that of the simulation result is 3762.9 psig. This gave an absolute deviation of 0.774 %, a satisfactory match to the laboratory (experimental) data. This show that equations of state, when sufficiently tuned can simulate the PVT properties of reservoir fluids, and can minimize the need to perform complete set of experimental PVT tests (DL) on each and every new reservoir fluid.

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

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.

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.

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.

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.