bluuebunny/crossref_metadata_2025 huggingface dataset:
Uncertainty Quantification of Top Structures in 3D Geocellular Models
Authors: Bansal R. S. , Vargas-Guzmán J. A.
Published: September 2015

Building a stochastic structural 3D geocellular model for a reservoir in a new field is a challenge because of insufficient well data. Structural heterogeneity due to folding, faulting and/or associated erosional unconformities may not be completely captured by low resolution seismic and limited well data. This could lead to significant structural uncertainty. Hence, quantification of uncertainty capturing structural heterogeneity requires a comprehensive methodology incorporating seismic interpretation, well data and tectonic information. Experimental discrepancies between predicted and measured depths of horizons in newly drilled wells reveal strong drift, which require a nonstationary model. The physical way to create such nonstationary model is by using numerical paleo-geomechanical deformation algorithms to reconstruct the folding phenomena (e.g., finite elements). Such proposition requires a thorough understanding of rock parameters, and boundary conditions. Another plausible alternative is to use nonstationary geostatistics, because it does not require boundary conditions, or rock deformation parameters. Nevertheless, representing finite differences of order-k, which are required for geostatistical modeling, may be unachievable with insufficient well data. After revisiting the theoretical aspects of the problem, this paper shows a fast approach to quantify the structural uncertainty range for the depth of horizons accounting for spatial drift. The approach is illustrated with an example for a real clastic reservoir.
An Integrated Approach to Quantify the Impact of Geological Heterogeneity on Connectivity in Deep-Water Reservoirs
Authors: Gonano Giacomo , Catanzaro Massimo
Published: September 2015

The purpose of the study was to quantify and evaluate the impact of geological heterogeneities on connectivity in channelized turbidite reservoirs. The main technical objectives of the project were: the identification of the architectural elements of the deep-water system under analysis, the development of different geological models, the quantification of reservoir heterogeneity and the evaluation of reservoir connectivity and the outline of an early appraisal strategy.

An integrated approach was applied, using different frameworks, to two eni's deep-water assets: the first, an exploration asset in the Mediterranean, and the second, a West African field in development. This methodology was based on an earth models construction phase (reservoir characterization and reservoir modeling) and on a dynamic simulations phase (streamline simulations and well test simulations).

Reservoir characterization was performed by interpreting 3D seismic data using a high precision 3D seismic interpretation software. Key surfaces were interpreted in the reservoir interval. Furthermore, deep-water elements and architectures, mainly stacked channels and distal lobes, were duly identified through the interpretation of seismic sections and amplitude maps.

Reservoir modeling consisted of Object-Based and Multi-Point Facies Simulation (MPFS) approaches. A sensitivity analysis was carried out to define critical parameters and their ranges in order to fully capture geological uncertainties and realize different static models. The selected parameters were: seismic conditioning in the MPFS (amalgamation), facies volume fraction, channels shape and shale drapes content.

To quantify heterogeneity and analyze connectivity, streamline simulations were carried out using a Streamline Simulator. For each geological model, a Dynamic Lorenz plot (storage capacity vs. flow capacity) and its related coefficient (standard measure of heterogeneity) were determined using an in house code. It resulted that all the selected parameters, except channels shape, impacted considerably on connectivity.

To outline an early appraisal strategy, well test simulations were performed using an hypothetical exploration well and a standard Dynamic Simulator. Well test simulation was found to be an interesting qualitative tool to identify heterogeneities, especially shale drapes content, and condition further appraisal decisions.

Considering the promising results, this approach will be further developed to effectively reduce the range of uncertainties, mitigate the associated risks and guide appraisal strategies in future deep-water prospects.
A comprehensive approach for CO2 Miscible Injection Piloting in a Giant Carbonate Reservoir in Middle East
Authors: Aissaoui Karim , Pradhan Akshaya Kumar , Jasser Majdolin
Published: September 2015

CO2 flooding is known to be one of the most applied miscible EOR process in E&P industry given its ability to mix with reservoir oil and form a miscible flood at relatively low reservoir pressures. CO2 EOR pilots' locations selection, configurations and design are key for success of an EOR piloting scheme. This goes without withstanding detailed compositional simulation to replicate components exchange under the MCM process as well as potential implications on existing well completions and surface facilities.

A structured workflow was established to rank and prioritize all reservoir units in terms of their suitability for miscible EOR. A thorough scrutiny of pilot locations, configuration as well as pilot design as a whole was undertaken. This was aimed to short-list preferred pilot locations and configurations that address most of remaining uncertainties. It was also intended to establish a list of expected deliverables from the pilots. Numerous pilot configurations were analyzed and ranked based on the size of EOR prize, uncertainties reduction as well as capturing synergies and common objectives across the reservoir units.

Detailed compositional simulation studies are being undertaken. This included one-dimensional models for the purpose of examining the displacement process; 2D mechanistic models to assess the impact of heterogeneity on the displacement process as well as fine grid pilot models for the purpose of optimizing the pilot design. A probabilistic production forecast of each pilot is also considered aiming to capture a range of possible outcomes and identify key uncertainties to be acted upon.

A tailored monitoring program is being designed to acquire key performance data including production and saturations monitoring, fluid sampling and pressures. This will feed inputs to sector model calibration as well as the evaluation of pilot performances.

Results from this study are expected to assist ADCO to plan and implement the EOR road map while accounting for all related issues such as flow assurance and asphaltene deposition, reservoir pressure maintenance, CO2 strip-out and re-injection as well as its impact on existing facilities.
A Novel Compositional Model of Simulating Fluid Flow in Shale Resrvoirs - Some Priliminary Tests and Results
Authors: Cao Yang , Yan Bicheng , Alfi Masoud , Killough John E.
Published: September 2015

Multiple porosity systems exist in shale reservoirs: organic matter, inorganic matter, natural fractures and hydraulic fractures. Accurately simulating fluid storage and flow in this complex environment still remains a challenge. One key is to properly account for the multi-component adsorption and diffusion phenomena occurring in the shale matrix. Most studies conducted in recent years use a single gas phase model or a black oil model to consider these aspects. A compositional model specifically tailored for the characteristics of shale reservoirs is required to properly model all of the physics.

In this paper, such a compositional model is introduced. The model takes the pressure and component molar masses as the primary variables, and applies the IMPEM method (implicit pressure and explicit mass) as the solution technique at the current stage. The multi-component adsorption and diffusion terms are incorporated into the component mass balance equations. Adsorption is described through the Extended Langmuir equation, and multi-component diffusion can be described either through the classical or the generalized Fick's law. The latter has the capacity of accounting for component interactions and the phase thermodynamic non-ideality. Knudsen diffusion can also be incorporated through the concept of an augmented effective diffusion coefficient.

Several preliminary tests have been conducted to validate the model. The influences of the important parameters, such as total carbon content, wettability, and fluid composition, on shale reservoir fluid recovery were also investigated with the new simulator.
A New Coupled Axial-Radial Productivity Model for Horizontal Wells with Application to High Order Numerical Modeling
Authors: Cao Jie , James Lesley A. , Johansen Thormod E.
Published: September 2015

For long, highly productive wells, frictional pressure loss cannot be ignored. The axial flow along the well trajectory in the near-well region must therefore also be considered. A new, fully analytical model for coupled radial well inflow and axial reservoir flow has been developed. The new model will be briefly reviewed and solutions to steady state flow summarized.

A discussion on the usage of the new model in simulation of horizontal wells together with its numerical performance compared to standard finite difference methods will be presented. The new analytical model has been used in the formulation of a numerical scheme for simulation of coupled well inflow and near-well reservoir flow. The analytical model results in a linear pressure distribution in the axial direction and a logarithmic pressure distribution in the radial direction in each near-well reservoir segment. Therefore, the pressure distribution is piecewise linear/logarithmic, contrary to existing piecewise constant distribution resulting from a standard finite difference method. Calculation examples are presented applying both the new method and the standard finite difference method to determine the pressure profiles and flow rates in both the wellbore and the near-well reservoir. Numerical results show that the new method represents a substantial improvement compared to a standard finite difference method, requiring fewer segments to achieve the same accuracy. The new method is more accurate especially near the heel, where accuracy is most important. This numerical scheme has also been proved to be higher order accurate in space discretization than a standard finite difference scheme. Since the axial flow rate is built into the new model analytically, the need for local grid refinements around the well is reduced.
Different Methods of Modeling Tilted Free Water Levels and the Impact on Field Production
Authors: Gao John , Schrijver Bart
Published: September 2015

This paper presents and compares the results of the creation of a titled Free Water Level (FWL) from two different modeling methods and the impact on field production.

Worldwide there are examples of oil and gas fields with tilted FWL's. These can be generated by different mechanisms. This paper focusses on the modelling of a tilted FWL associated to a hydrodynamic system. There are several methods of modeling a tilted FWL, most of them emphasize on how to create a tilted FWL but lack the correctness of pressure distribution. Two modelling methods were investigated and their results were compared. One is a static method in which a tilted FWL surface is assigned and the respective water saturation (Sw) values are calculated in the model. The second approach is a hydrodynamic method based on the hydrodynamic principle that a tilted FWL is generated by lateral pressure variation related to a water flow below the hydrocarbon bearing interval. Both methods can generate a correct tilted FWL surface and the associated water saturation distribution, but the pressure distribution shows a significant difference depending on which method was applied. The hydrodynamic method delivers a correct pressure distribution in both the hydrocarbon and the water zone as it captures the physical principals of the tilted FWL and aquifer and therefore the corresponding pressure data. In the field-model a realistic stronger pressure support can be observed, leading to realistic recovery figures. The static method provides a correct pressure distribution in the hydrocarbon zone but not in the water zone, and delivers a nonrealistic weaker pressure support, leading to lower production figures. The fundamental difference in pressure distribution has a signiciant impact on a field production and therefore project economics.

In conclusion, proper tilted FWL modeling should provide not only a correct FWL surface but also pressure distribution. In cases where a tilted FWL is associated to water flow below the hydrocarbon zone, the hydrodynamic method based on the hydrodynamic principle is recommended.
Single Sandbody Stacking Pattern, Calcareous Barrier and Fracture of Tight Low Permeability Oil Sandstone Reservoir and their Impact on Water-flooding - A Case Study of Ansai oil field, Ordos Basin, China
Authors: Li Jiahong , Song Xinming , Tian Changbing , Wang Youjing , Xu Feng , Hui Gang , Wang Ruigang
Published: September 2015

Similar to conventional medium-high permeability reservoirs' water-flooding process, quite a number of tight low-permeability sandstone reservoirs (average permeability<10mD) in China have reached a high water-cut ratio of over 60%, after decades of water-flooding. Despite of the high WC, these reservoirs' recovery remains less than 14%. Heterogeneity caused by matrix and fracture is desperately in need to be characterized to curb the drastic production decline.

A systematic reservoir description workflow of C61 delta-front formation, Ansai oil field, was run, based on outcrop, densely-spaced well cores and loggings. 3 types of single sandbodies and 9 types of single sandbody stacking patterns were recognized and summarized, from the perspective of matrix heterogeneity. Also, hydraulic fractures near producers and dynamic fractures near injectors deriving from fracture reopening by injection pressure accumulation, are descripted. A fine-scale geologically conceptual model embracing information of single sandbody stacking patterns, calcareous barriers and fractures near wells, was then established to quantitatively evaluate the water-displacement differentiation between tight and conventional reservoir, and the impact of stacking pattern, barrier and fracture on tight oil sandstone reservoir recovery.

Simulation results indicate that, (1) water-flooding front in tight sandstone matrix runs slowly but relatively homogeneously compared with in conventional reservoir matrix, especially showing no conspicuous vertical tonguing or fingering; (2) these 9 stacking patterns differ by petrophysical property, barrier frequency and mutual erosion extent, the first 2 factors of which exert dominant controls on water-flooding; (3) calcareous barriers inside composite sandbodies deteriorate vertical displacement homogeneity, and block water-front near erosion interfaces to certain extent; (4) connectivity of these stacking patterns were then evaluated comparatively based on petrophysical property and barrier frequency; (5) heterogeneity derived from fractures, prevailing matrix, triggers oriental flooding along the in-situ maximum principal stress direction.

Fracture, especially the inevitably dynamic fracture in water-flooding, predominates in tight oil sandstone heterogeneity. How to harness fracture with matrix and design compatible well pattern would be the primary issue to be handled for tight oil sandstone water-flooding.
History Matching by Online Metamodeling
Authors: Sayyafzadeh Mohammad
Published: September 2015

The high computational costs associated with reservoir simulation create a major barrier in history matching problems. Within the past decades, several efforts have been made to reduce CPU-time by metamodeling (proxy-modeling) techniques in which the original fitness function (OF) is partially or completely substituted by an approximation-function (AF), often called metamodel or surrogate. In order to build a high-fidelity surrogate, usually a large number of training samples is required. This can make the traditional surrogate-assisted algorithms, inefficient. In recent years, it has been shown that to approximate the global optimum using a surrogate-assisted algorithm, the AF does not necessarily need to be of high-fidelity, if it is applied in conjunction with the OF and retrained online, during the optimization process.

In order to use the OF effectively and minimally, a model-management strategy is required. In this study, a new adaptive model-management strategy is proposed, in which a second surrogate is required. The first surrogate approximates the original fitness function landscape, and the second one estimates the fidelity of the first surrogate over the search-space. On the basis of the estimated fidelity, a probability for employing the OF is calculated, and then according to the calculated probability, the algorithm stochastically decides to use the OF or the AF. A heuristic fuzzy rule is also applied to adjust the possible range of probability values in each evolution-cycle, based on the average fidelity of the second surrogate.

The robustness of the proposed algorithm is analyzed using different analytical benchmarking functions, and a semi-synthetic history matching problem, IC-fault model. To deliver a comparative study, the optimization is also carried out using three other algorithms, without metamodeling (OF-only), offline-learning (AF-only), and online metamodeling with a predefined and constant probability. The outcomes of all four algorithms are compared with each other. The assessment shows that the proposed method can reduce the computational costs significantly.
Integrated Numerical Simulation for a Giant, Asphaltene Riched, Carbonate Reservoir
Authors: Bingyu Ji , Peiqing Lian , Xuequn Tan , Taizhong Duan
Published: September 2015

Fah reservoir in Y oilfield is a giant, pore-typed, carbonate reservoir, which have high heterogeneity and asphaltene deposition during production process. In order to describe the heterogeneity of Fah reservoir, fomulas of pore throat radius, porosity and permeability under different mercury injection saturation was fitted. It shows 30% is the best percentile, and R30 method was presented for rock typing. Six rock types were divided according to pore throat radius, the porosity-permeability relationship was established for each rock type. The rock types of the non-cored wells are predicted by KNN (K nearest Neighbor) method. After the rock types of all wells have been obtained, 3D rock type model was built by sequential indicator simulation, and the 3D porosity could be established on the basis of the rock type model, logging interpretation and sesmic data. 3D permeability model was calculated according the relationship between porosity and permeability. Comparing core permeability and calculated permeability obtained by the rock types, it shown very good coincidency.

During the oilfield development process of Fah reservoir, the asphaltene deposition is very serious, which cause the production decline. Therefore, it is quite necessary to carry out the asphaltene deposition study. Based on the experiment research, the phase behavior of the asphaltene was studied, and the asphaltene precipitation envelope diagram was drawn on the basis of the gas-liquid-solid three-phase equilibrium theory. A fine numerical simulation model to simulate asphaltene precipitation, flocculation, deposition and damage processes was established, the impact of asphaltene on recovery was studied and the recovery of 10 years was declined by 2.3% in considering asphaltenes. By controlling the bottomhole pressure, the asphaltene precipitation in the formation could be prevented. In order to study the asphaltene depostion in the wellbore and the surface pipeline, a reservoir, wellbore and surface pipeline integrated model was built by coupling the Eclipse and IPM software together, and the pressure and temperature from reservoir to separator can be predicted, then compared with precipitation envelope diagram, the location of asphaltene precipitation could be determined accurately.
New Solution to Pressure Transient Equation in a Two-Layer Reservoir with Crossflow
Authors: Lu Jing , Zhou Botao , Rahman M. M.
Published: September 2015

A two-layer reservoir with crossflow was erroneously taken as a dual-porosity-dual-permeability naturally fractured reservoir in the literature, and the solutions obtained from dual-porosity-dual-permeability model cannot account for the characteristics of two-layer reservoir.

This paper presents a new mathematical model and an analytical solution to the pressure transient equation of a uniform-flux fully penetrating vertical well in a two-layer reservoir with crossflow. The pressure of a vertical well producing a two-layer reservoir with a constant rate is examined. The pressure response is observed in three stages: first, it is identical to the commingled system, because the crossflow is so weak at the production beginning that we can ignore it. Second stage is transition stage and the third stage, which is same as the homogeneous system. What's more important, we propose a parameter to describe the crossflow in a two-layer reservoir quantitatively. It is verified that the crossflow coefficient is not constant, but a function of the time and distance away from the wellbore.

These solutions are obtained by using Laplace transform, double Fourier transform and Green's functions method with numerical approximations. These solutions give results accurate enough for practical applications and allow to estimate the effects of formation properties on pressure behavior both at large distance from the wells and at the wells. When all the corresponding parameters are identical in each layer, the proposed solution for a two-layer reservoir reduces to the solution for a single layer reservoir.

The solution procedure proposed in this paper is a fast tool to evaluate a vertical well performance in a two-layer reservoir.
Production History of a Hetergenous Carbonate Reservoir Dictates New Factors to Optimize New Well Placement in a Miscible Gas Injection Field-a Case Study
Authors: Hashemi Abolfazl , Miri Bahram , Chegeni Reza , Namdarian Fatemeh , Taghanaki Morteza Aghababee , Karami Mehran
Published: September 2015

Defining in-fill drilling locations seems a simple task in natural depletion reservoirs while in special fields like those under miscible gas injection operation is challenging. The aim of this paper is to scrutinize the production and injection of existing wells and derive some extra rules to optimize the new well placement in miscible gas injection fields.

DGN is an undersaturated light oil field situated in south west of Iran. The field has been producing since 2003 and miscible gas injection started in 2009. After 5 years of miscible gas injection, unexpected and different types of breakthrough happened in some producing wells which made defining new well locations a challenging task. Gas injection has sweeping role as well as pressure maintenance, and based on studied reservoir heterogeneity the latter one was recognized as a dominant factor. After reviewing all available studies and static and dynamic models as well as real field production and welltesting data, some rules were extracted to narrow the window to some specific regions. Therefore, a new gas injection well was spotted on the anticline of the reservoir even close to other injection wells and five new locations were decided. Afterward, they were put into dynamic model and their production was compared. At the end, those wells with better performance were given higher priority and sent for drilling.

Considering recovery factor of the reservoir, it indicates that new gas injection well can have better performance on the crest of the reservoir even in the vicinity of the other injectors, and oil producing wells should be in symmetrical pattern, down-dip and farthest from injection wells.
A Miscible EOR Project in a Mature, Offshore, Carbonate Middle East Reservoir – Uncertainty Analysis With Proxy Models Based on Experimental Design of Reservoir Simulations
Authors: Bevillon Damien , Mohagerani Saeid
Published: September 2015

This paper presents the reservoir modeling and an improved engineering workflow to perform a technical evaluation of an EOR miscible hydrocarbon gas injection project using horizontal wells. This project was performed in the Fateh Mishrif, a large carbonate reservoir in a Middle East offshore operating environment. A new methodology to generate synthetic forecast of EOR oil and gas profiles is proposed. The paper describes the technical approach followed to assess the impact of uncertainties and the process used to carry them forward into a probabilistic uncertainty analysis.

Experimental Design and proxy model techniques with associated algorithms, uncertainties, bias, and accuracy vs. simulation models have been discussed through numerous papers. These papers usually present discrete results such as Cumulative oil, STOIIP, or NPV though proxy allowing a simple and time saving solution compared to resource consuming compositional simulations.

The new tool developed here allows for rapid re-computing of a full “synthetic” EOR oil and gas profile (or Response Function) build on 6 essential parameters (EOR breakthrough time, oil ramp up, peak oil, peak oil time, decline, cumulative oil), which are identified as the typical signatures of EOR oil and gas response to miscible gas injection. The EOR profiles are designed for patterns representing the Field Development Plan. The 6 parameters are individually computed through their own proxy models and are a function of 19 inputs parameters. Each proxy model is built based on Experimental Design simulations with Latin-hypercube method which runs hundreds of simulation cases based on the 19 uncertainty parameters. Iterations process with a sufficient number of runs ensures the reliability of the proxy model (Polynomial Regression) vs. simulations with minimizing error.

The response of EOR oil and gas can be predicted as a function of a range of uncertainty with parameters such as rock properties, PVT, as well as operational parameters such well performance, gas injection rate, and WAG management. A work based on lab data, simulation history match, and literature has been achieved for the description, selection, and settings of the boundary values of each parameter to minimize bias.

Response Functions are ready for roll up process for the EOR Field Development Plan through a spreadsheet and for decision making by use of uncertainty analysis.
Development and Validation of an Iteratively Coupled Geomechanics Module for a Compositional Reservoir Simulator, UTCOMP
Authors: Haddad Mahdi , Al-Shalabi Emad W. , Sepehrnoori Kamy
Published: September 2015

Pore pressure-stress analyses in stress-sensitive reservoirs investigate interactions between the in-situ stress and fluid flow; these interactions help or resist production, or conclude surface subsidence during production. Among the tools for these analyses, an iteratively coupled Geomechanics and fluid flow model provides an essential and reliable prediction for field planning and development. In this work, we implemented this model in an in-house, three dimensional, compositional reservoir simulator, UTCOMP, using modified Chin’s iterative coupling method. This development integrated a stand-alone Geomechanics module based on finite element method with the reservoir simulator, an advantage of our coupling algorithm, and improved our understanding of the production through various enhanced oil recovery processes such as water and CO2 floodings previously coded in UTCOMP. Benefiting from the higher time scales of solution variations due to the Geomchanics module, we lowered the frequency of calling this computationally expensive module. Also, we reduced the order of the finite element shape functions from quadratic to linear, which majorly mitigated the high computational cost of our Geomechanics studies while we almost maintained the solution accuracy. To validate our implementation, we investigated a primary oil production case and compared the results from UTCOMP with those from two other simulators: 1) CMG software program using different coupling methods; and 2) another pre-validated in-house reservoir simulator, GPAS. Moreover, due to the lack of real field data, we validated our solutions for the enhanced oil recovery problems by comparing them with those from GPAS coupled with Geomechanics. We observed a minor discrepancy between the solutions at very early times which originates from the different structures in these two reservoir simulators, IMPEC in UTCOMP and fully implicit in GPAS.
A Novel Approach for a Fast and Accurate Petrophysical Characterization of Carbonate Reservoirs Based on NMR
Authors: Pirrone M. , Bona N.
Published: September 2015

This paper discusses the use of a novel methodology for the petrophysical characterization of carbonate reservoirs. The methodology makes use of nuclear magnetic resonance (NMR) log and core data and provides direct and fast estimates of downhole porosity, pore size, petrophysical rock types, irreducible water saturation and permeability. The novelties of the approach lie on the developed permeability model and the critical role played by effective surface relaxivity. It is shown that if this parameter is properly defined, NMR logs do not need any additional calibration.

The methodology is demonstrated for a Cretaceous carbonate reservoir in the Middle East. A dataset comprised of NMR log acquired on one key well and special core analysis results from seven wells is utilized. Fifteen other wells are used as blind tests, once the model has been calibrated. Generalization to other carbonate reservoirs is then discussed.

In details, a pore size distribution predictor is defined, which makes use of a system built upon mercury injection measurements and is able to discriminate micropores, mesopores and macropores downhole. Making this categorization is fundamental for reservoir modeling purposes, fluid-flow behavior assessment and to understand wettability. Micropores are associated with bound fluids, so the aforementioned porosity partition supplies also an estimation of irreducible water saturation. The established link between NMR transverse relaxation time distributions and pore size distributions provides a direct estimation of NMR effective surface relaxivity, both at laboratory and reservoir conditions. This parameter is fundamental since it represents the main driver for the subsequent computation of permeability, by means of a new and advanced modeling. The overall good match between the entire NMR-based interpretation and core data demonstrates the reliability of the methodology.

Although several approaches exist to aid formation evaluation in carbonates based on quantifying rock texture by NMR, the quantitative use of effective surface relaxivity is relatively new and can shed new light on this topic.
Characterization of Coquinas and Dolomites Integrating Electrical Resistivity, Nuclear Magnetic Resonance (NMR) and Porosimetry by Mercury Intrusion (MICP)
Authors: Fiorelli G. L. , Winter A. , Koroishi E. T. , Trevisan O. V.
Published: September 2015

This study aims to characterize carbonate rocks outcrop with similar petrophysical properties of the Brazilian pre-salt by three different methodologies: Electrical Resistivity, Nuclear Magnetic Resonance (NMR) and Porosimetry by Mercury Intrusion (MICP) at room conditions. The rocks are coquinas from the Coqueiro Seco Formation at Sergipe Basin - Alagoas, Brazil, and Silurian dolomites from the Thornton formation, in United States. The rock samples were analyzed for varying brine / air / oil saturations by measuring electrical resistivity and magnetic transverse relaxation time (T2) at each level of saturation. Samples were also analyzed for throat size distribution using the technique of porosimetry by mercury intrusion (MICP). The relaxation time results show that the pore structures of the two carbonate rocks have pore size distributions of multimodal character. The coquinas and dolomites are composed mostly of macropores structures with a small fraction of micropores and mesopores. Nonetheless, the MICP results showed distinct distributions of pore throats. While coquinas present pore and throats of similar dimensions, dolomites have a significant amount of pores, mainly macropores, connected through restricting throats. The resistivity index curves for water/air saturations are typical, with a linear behavior, for both rocks. Coquinas kept a similar behavior when saturated with water and oil. However, dolomites tested with water/oil showed a double linear trend. The narrow throats seem to contribute to isolate water in the smaller pores at the lower range of water saturation.
Water Flooding Optimization for a Super-Giant Carbonate with Thief Zones
Authors: Wei Chenji , Li Yong , Li Baozhu , Wang Yinxi , cai Kaiping , Zhang Qi , Zhou Jiasheng
Published: September 2015

Understanding the heterogeneity is critical for a successful water injection in a carbonate reservoir. Thief zone is one of the most obvious forms of heterogeneity, which indicates the thin layer with higher permeability compared with average reservoir permeability. The existence of thief zone results in earlier water breakthrough and faster water cut increase, which lead to smaller sweep efficiency and lower recovery factor. Therefore, determining the thief zone distribution and proposing corresponding development plan are very important.

This paper focuses on a super-giant carbonate reservoir, which is a Cretaceous carbonate reservoir in Middle East, with an OOIP of more than 20 billion barrels. Thief zones are widely distributed in this carbonate according to the production logging test (PLT). In this paper, we combined geological understanding and dynamic behavior to summarize different types of thief zone distribution, which means the different locations and scales of thief zone and barriers. Then, geological model is built, and reservoir simulation is conducted on the models corresponding to different types to optimize the development strategy.

The optimized parameters include well pattern and perforation strategy. Then, development strategies are proposed for different types of thief zone distribution. Results indicate that location of thief zone hasobvious impact on the production. In order to mitigate the impact of thief zone, line drive pattern is preferred when the permeability ratio is high. Most importantly, different types of thief zone distribution require specified perforation strategy, and optimizeddevelopment strategies could save more than 25% of injected water by mitigating the futile cycle of injected water.

This paper offers a case study that summarizes different types of thief zone distribution and optimizes the development strategy for different scenarios. It also provides a methodology and reference case for engineers and geologists to develop other similar fields.
A Case Study: Modeling Challenges of Miscible Gas Injection (MGI) Project of Tight Sour Oil Field Developed with Hydraulically Fracced Wells
Authors: Cobanoglu M. , Mahruqi F.
Published: September 2015

The reservoir in South Oman – discovered in 1989 – is a 400m thick, tight, micro-porous silicilyte slab encased in salt at a depth of 4000m. The field contains the unique Athel silicilyte formation, some 4 km below the surface and is fully encased in salt as a result of which the reservoir is over-pressured at 800 bars.

The crestal area has average matrix porosity of 22% and the permeability of the reservoir is extremely low (typically 1 – 100 μD). The oil in this field is very light, sour, low viscosity and volatile (48° API, Pb=260 bar, H2S=1.5mol%, CO2=2.5mol%). The application of massive hydraulic fracturing (2-5 fracs/per well) combined with the favorable oil properties and undersaturated nature of the oil has made economic primary depletion development possible in this low permeability reservoir with initial oil rates in the range of 100-600 m3/day. Current oil recovery factor is 4.2% and expected to reach 10% through continued primary depletion.

MGI via hydraulically fractured wells is seen as possible EOR method to improve field recovery. A pilot injection phase consisting of 2 inverted 5-spot patterns in the crest of the reservoir will start Q2-2015 followed by a 2nd phase of crestal MGI by 2026. The purpose of the current dynamic modeling is to assess the 2nd phase of crestal MGI.

The modeling challenges are complex reservoir characteristics (vertical and areal heterogeneity), tight reservoir nature, hydraulically fracced wells, sour content and MGI. The subsurface complexity requires a detailed static model (areally and vertically) combined with preferably a compositional dynamic model. Obviously, run time of a compositional dynamic model is increasing dramatically with increasing complexity which is limiting the practical applications.

Several solutions to optimize the running time and accuracy have been investigated (i.e. explicit or implicit modeling of fracs, rate or THP control, black oil versus EOS models, various up-scaling options, sector versus full field models), tested and calibrated with historical data. In addition, history matching of more than 14 years production history of 43 wells with 25 fracs/well was another significant challenge. Different approaches, e.g. single/multiple case deterministic (MultiRun) and Design of Experiments (DoE) approach have been investigated for both history match and forecasting.

This paper covers a fit for purpose modeling approach, using Shell’s in-house simulation tool MORES, with powerful functionalities that enable modeling of the subsurface complexity in order to make the field development decision on the MGI extension. In addition, successful application of uncertainty modeling and assessment by using a classic approach (i.e. deterministic models) and a stochastic approach (i.e. DoE using assisted HM methods) will also be covered in the paper.
Innovative Integration of Subsurface Data and History Matching Validation to Characterize and Model Complex Carbonate Reservoir with High Permeability Streaks and Low Resistivity Pay Issues, Onshore Abu Dhabi
Authors: Salahuddin Andi A. , Gibrata Muhammad A. , Uchida Miho , Al Hammadi Khaled E. , Binmadhi Abdulaziz K.
Published: September 2015

Complex carbonate reservoirs provide many challenges for characterization and modeling not least because diagenetic overprints may lead to increases in heterogeneities on a small scale. This study examines a complex carbonate reservoir from onshore Abu Dhabi where diagenetic overprints have led to the development of high permeability streaks. Additional complication is the presence of a low resistivity pay (LRP), where analysis of resistivity logs has resulted in the calculation of high water saturation which contradicts production tests that confirm dry oil.

This study used a combination of core, thin section, MICP, well logs and dynamic data to develop a holistic and robust reservoir characterization and reservoir model. A methodology was developed specifically to characterize and model the subsurface conditions identified in this field due to the simultaneous existences of high permeability streaks and LRP intervals. The methodology included:

detailed core, thin section and lithofacies description; paleoenvironmental interpretation; high resolution sequence stratigraphy (HRSS) interpretation; diagenetical analysis; reservoir rock typing (RRT); assessment of the relationship between lithofacies, diagenetic processes, and RRT; saturation height function (SHF); integrated static model building, and; flow simulation and history match validation.

Three lithofacies were identified using faunal content, texture, sedimentary structures and Dunham Classification. The depositional setting varied from lagoon to shoal. Reservoir Rock Typing (RRT) defined seven rock types based on capillary pressure trend, pore throat distribution and porosity-permeability. HRSS interpretation recognized three 5th order highstand sequences that separated by two transgressive sequences. This has then allowed the identification of the origin of the high permeability streaks and the spatial distribution within the sequence stratigraphic framework. Detailed geological modeling was then integrated with dynamic data to provide a robust dynamic simulation validation. The combination of static and dynamic modeling can then be used to more accurately calculate OOIP and optimize the current reservoir management plan ensuring optimal sweep efficiency and recovery.
Field Development Strategy through Full-Filed Reservoir Simulation Considering Asphaltene Precipitation and Deposition
Authors: Attar Masoud Seyed , Sedaghat Mohammad H , Kord Shahin , Mayahi Hamid
Published: September 2015

Reservoir simulation is an integrated tool for predicting reservoir performance and proposing development plans. However, in the master development plan (MDP) proposed based on the simulation results, there is always an associated risk that must be minimized. This risk arises from many different sources, one of which is the complexity in petroleum reservoir fluid. On the other hand, asphaltene precipitation and deposition can dramatically affect the reservoir rock and fluid properties.

Asphaltene deposition may cause severe problems during different stages of oil recovery and can affect the reservoir performance through porosity and permeability reduction and wettability alteration. These effects can be modeled in compositional simulation using parameters that are usually estimated from precipitation tests and core flooding deposition experiments. Through a series of experiments, the asphaltene stability envelope and permeability impairment are established for several bottomhole live crude oil and reservoir core samples during pressure depletion and gas injection processes. Using the parameters obtained from the experiments, precipitation and deposition of asphaltene are investigated at field scale by a compositional simulator, and a comprehensive development plan is suggested for the reservoir. Also, the effect of asphaltene deposition on fracture parameters is investigated.

The results show that dynamic and static parameters of asphaltene precipitation and deposition play an important role in the prediction of formation damage and field performance during natural depletion, gas injection and water flooding. Moreover, the results confirm that the permeability reduction due to asphaltene deposition is more considerable in the fractures than in the matrix media.
A Dual Multilateral Completion as an Alternative to Un-Wanted Water Control in Horizontal Wells
Authors: Magzoub Musaab Ibrahim , Hossain M. Enamul
Published: September 2015

Worldwide water production (e.g. also called as un-wanted water) creates huge oil fields problems. An estimate shows that the average of three barrels of water is produced for each barrel of oil. The common practice in vertical wells is to block the water zone and perforate above. However, in horizontal zone if the oil-water contact (OWC) reaches the horizontal section, the well will be abandon. In literature, there are many methods used to delay water break though. Horizontal wells increase the potential of OWC movement due to the phenomena of high velocity of flow near heal compared to toe.

Horizontal wells have been increased significantly for last twenty years and almost replaced the vertical wells. Moreover, horizontal drilling has become a common practice with recent technology and advanced tools. As a result, the technology starts moving towards multilateral wells and extended reach drilling. In addition, some geological and reservoir cases put horizontal well in a challenging position. But still no one can deny advantages of horizontal wells and its contribution to the oil production and increasing exploited reserves. This article addresses the most exhibited challenges faced in horizontal well completions. In addition, the paper proposes the dual multilateral drilling and completion strategy and compares the proposed method with the conventional solution by ICDs and ICVs. A case study is also presented to show the effectiveness of the proposed strategy.

The problem with the existing practice is that the velocity of flow at heal is very high compared with the toe of a horizontal section. This situation causes many problems especially when there is permeability or pressure variations. It becomes even worst when the horizontal section is near the water- oil contact (OWC). The OWC below the horizontal section will be disturbed and this leads to early water break through. ICV is used to choke the heal area or some perforation design technique. All these techniques are based on reducing the production from that area. This article outlines how to tackle this issue using the proposed dual lateral completion while allowing the production to be increased within wider save margin. This method will be useful for enhancing the production and reducing the water break through for a reservoir.
Software-Generated Operating Envelope for Underbalanced Drilling Operations
Authors: Huang Xiaoqian (Christina) , Urdaneta Gustavo , Poletzky Isabel
Published: September 2015

Traditionally, several multiphase hydraulic calculations are required to determine the permissible surface-parameter operating envelope in underbalanced drilling (UBD) operations to estimate how bottomhole pressure (BHP) and the desired underbalanced condition can be achieved. Furthermore, the complexity consists of running several combinations of gas- and liquid-injection rates and overlapping these results with operating constraints, including the operating range of equivalent liquid rates for downhole mud motors, minimum annular velocities for effective hole cleaning, desired BHP, and respective surface-equipment limitations, to visualize a comprehensive spectrum of viable surface parameters. This paper explains and illustrates a novel method for obtaining quick and comprehensive operational envelopes for underbalanced drilling operations.

The model used for pressure-drop calculations considers the effect of geothermal and string temperatures, detailed drillstring and wellbore geometries (including tool joints), formation fluid influxes at several depth intervals, cutting-slip effects, and surface back pressure. This model also enables the evaluation of the behavior of multiphase drilling fluid using different gas correlations.

The system determines bottomhole pressures for several combinations of injection parameters and automatically collects results to generate a permissible operating area (envelope).

Measured times to generate the operating envelope graph and a comparison of the results are evaluated for several methods and wellbore hydraulic simulators; a qualitative evaluation and validation against field data is also included. The method outlined in this paper offers an alternative to automatically obtaining a gas- and liquid-injection operating envelope, which results in a time savings of three orders of magnitude, as compared to traditional procedures and computational solutions.

One of the limitations of the model is that the operating envelope is for a single wellbore depth and provides a representation of the pressure achieved at a fixed depth. Recommended developments will consist of the ability to visualize BHP values for drilling depths, perhaps through a 3D graph.

This paper describes the method used by a multiphase flow simulator to create a graph that aids in determining and visualizing the operational area to achieve a specific BHP, including the hydrostatic and friction-dominant areas of circulation; this development will facilitate the decision-making process while designing the wellbore hydraulic aspects of an underbalanced drilling operation. The benefits of the multiphase flow simulator include a significant time savings to obtain a visual representation of bottomhole conditions and the ability to quickly achieve optimized results by means of a broader sensitivity analysis.