bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulation Study of Miscible Gas Injection for Enhanced Oil Recovery in Low Permeable Carbonate Reservoirs in Abu Dhabi
Authors: van Vark W. , Masalmeh S. K. , van Dorp J. , Al-Nasr M. Abu , Al-Khanbashi S.
Published: December 2007

In this paper we will present the outcome of a study conducted to evaluate the feasibility of large scale injection of sour and/or acid gas into a low permeable carbonate reservoir to enhance oil recovery.

Other than for disposal, H2S containing mixtures have rarely been injected as a miscible agent in oil recovery projects. Moreover, the very few projects that have actually been executed are relatively small (generally less than 10 MMscf/d).

In this study different recovery processes were evaluated such as water flooding, lean gas injection, sour gas (natural gas with a large H2S content) injection, acid gas injection, acid gas (mixture of H2S and CO2) after a slug of sour gas and CO2 injection. To evaluate these different (EOR) recovery processes, a detailed reservoir description is essential and for this purpose element-models were used.

The critical importance of a thorough understanding of reservoir geology and rock properties for miscible gas injection schemes has been confirmed by the experiences of water breakthrough and over-ride in a number of reservoirs in Abu Dhabi and the poor performance of some miscible gas injection projects in the industry.

The simulation study shows that miscible acid gas injection is the preferred recovery mechanism for part of the reservoir under study. This is a result of several key factors, including the favorable miscibility with the native oil (lower miscibility pressure with reservoir crude), better solvent for asphaltene, a more favorable mobility ratio due to high acid gas viscosity and density and availability of large quantities of acid gas from the underlying formation. Acid gas is therefore an attractive, low cost, miscible, enhanced oil recovery agent, provided fully adequate corrosion mitigation procedures and HS&E management systems are implemented in the development.
New Method of Incorporating Immobile and Non-vaporizing Residual Oil Saturation Into Compositional Reservoir Simulation of Gasflooding
Authors: Hiraiwa T. , Suzuki K.
Published: December 2007

In compositional simulation of gas injection processes, it is often observed that grid-block oil saturations decrease far beyond the user-defined residual oil saturation, even under immiscible conditions. This numerical phenomenon occurs since oil components are allowed to vaporize into the gas phase as much as the phase equilibrium obtained with an equation of state (EoS) permits. Especially in the vicinity of gas injectors, the oil saturation of zero is sometimes predicted. On the other hand, such significant low oil saturation is rarely seen in laboratory data such as coreflood experiments and slimtube tests.

The reason of the discrepancy between simulation results and laboratory results described above is thought that bypassed oil located in dead-end pores or caused by subgrid scale heterogeneities is not considered in the current compositional simulation practice. To overcome this, we developed an innovative method of incorporating laboratory-based residual oil saturations. The proposed method can restrict the excessive vaporization and maintain the prescribed residual oil by accommodating a novel application of the transport coefficient (Ref. 1).
Hazard Management Considerations for Sour Gas Development During Concept Selection
Authors: Kamath A. R. Ramachandra , van Dorp Johan , Johnson Andy , Alcock Jane , Keith Ian
Published: December 2007

A systematic hazard management approach was used to identify, assess and mitigate hazards at the conceptual design stage of a large onshore sour gas development in Abu Dhabi. The potential environmental impact of sulphur block production and poor prospects of a sulphur market led to a concept involving injection of dense phase acid gas back into the formation. Significant Health, Safety and Environmental (HSE) challenges were addressed relating to the scale of the sour gas development which included the gathering, processing and injection of sour/acid gas containing 33% – 80% H2S. Quantitative Risk Assessment and H2S dispersion calculations were performed to evaluate the risk reduction effectiveness of specific HSE design considerations including material selection, pipeline design, pipeline routing, well design and the location of the processing facility and sour/acid gas wells. These HSE design considerations were integrated into the concept selection. Best industry practices in design and operation of sour gas facilities and emerging technologies in leak detection were adopted as a minimum standard to minimize the HSE risks.
High-Resolution Sequence Stratigraphy of the Kharaib Formation (Lower Cretaceous, U.A.E.)
Authors: Strohmenger Christian J. , Weber L. J. Jim , Ghani Ahmed , Rebelle Michel , Al-Mehsin Khalil , Al-Jeelani Omar , Al-Mansoori Abdulla , Suwaina Omar
Published: December 2007

A new sequence stratigraphie framework is proposed for the Lower Cretaceous Kharaib Formation (Barremian and Lowermost Aptian) of the United Arab Emirates. This framework is based on the integration of core and well-log data from Abu Dhabi oil fields with outcrop data from Wadi Rahabah, Ras Al-Khaimah (U.A.E.).

The Kharaib Formation is part of the late transgressive sequence set of a second-order supersequence, built by two third-order composite sequences. Fourteen fourth-order parasequence sets build into two third-order composite sequences and show predominantly aggradational and progradational stacking patterns, typical of greenhouse cycles.

On the basis of faunal content, texture, sedimentary structures, and lithologic composition, eleven reservoir lithofacies and eight non-reservoir "dense" lithofacies are identified from core. These same lithofacies are also identified in time-equivalent rock exposures studied in Wadi Rahabah. The analyzed lithofacies range from open platform, lower ramp to restricted platform subtidal to intertidal environments. Intensively bioturbated wackestone and packstone, and interbedded organic- and siliciclastic-rich limestone characterize the three so-called dense zones (Lower, Middle, and Upper Dense Zone). Locally, mud-cracks, blackened grains, and rootlets are observed. The two reservoir zones (Lower and Upper Kharaib Reservoir Unit) correspond to the late transgressive and, dominantly, highstand systems tracts characterized by parasequence sets that show shallowing-upward trends from open platform, burrowed skeletal wackestone to skeletal, peloidal packstone and algal, coated-grain grainstone/rudstone, and rudist, algal floatstone/rudstone. Well-developed Thalassinoides firmgrounds (Glossifungites surfaces) indicate temporary cessation in sedimentation and cap several parasequence sets and parasequences.

Stylolitic intervals within the reservoir units predominantly correspond to major facies changes related to third-, fourth-,and fifth-order sequence boundaries, parasequence set boundaries, and parasequence boundaries.

In outcrop, low-angle clinoforms that cannot be seen in core data are observed within the highstand systems tract of the upper third-order composite sequence (Upper Kharaib Reservoir Unit). Integration of subsurface and outcrop data leads to more insightful and realistic geological models of subsurface stratigraphy.
Integrated Characterization of UAE Outcrops: From Rocks to Fluid Flow Simulation
Authors: Vaughan R. L. , Khan S. A. , Weber L. J. , Suwaina O. , Al-Mansoori A. , Ghani A. , Strohmenger C. J. , Herrmann M. A. , Hulstrand D.
Published: December 2007

This paper describes a systematic and logical workflow for characterizing a UAE outcrop of the Upper Thamama reservoir. This integrated workflow uses sequence stratigraphy, geologic modeling, and fluid flow simulation and was used as a tool for training early-career UAE geoscientists and engineers. Although the primary focus of the paper is on the mechanics of geologic modeling with principles applicable to UAE fields, the integrated workflow covers the entire spectrum from rock characterization all the way to flow simulation.

Outcrop analogs are a valuable source of data for reservoir characterization. They are particularly useful for visualizing interwell variability because subsurface wellbores represent discrete widely spaced data. In other words, outcrops provide the continuous, large-scale coverage of a seismic line and provide the fine-scale resolution of core measurements. Modeling input parameters such as lateral and vertical continuity (variogram range), object dimensions (aspect ratios), detailed reservoir architecture (layering), facies relationships, and the nature and extent of diagenetic features can be observed and measured.

To better understand reservoir properties of the Upper Thamama producing zones in Abu Dhabi, a geologic model was developed from descriptions of time-equivalent, analogous outcrops in the Emirate of Ras Al-Khaimah. Parasequences, maximum flooding surfaces, sequence boundaries and lithofacies were described in four measured sections. Porosity measurements derived from logs, core porosity, and core permeability data from an Abu Dhabi oil field were applied to similar lithofacies observed in outcrop. These subsurface data were used in the outcrop 3D model to more precisely reflect subsurface reservoir behavior because outcrops in the UAE experienced a significantly different burial history relative to the subsurface reservoirs.1

For the stratigraphic interval studied in outcrop (i.e., Upper and Lower Kharaib Formation), four composite reservoir facies (three permeable and one "dense") adequately described the flow behavior. These reservoir facies were modeled using Petrel2 software and were scaled up into a simulation model using ExxonMobil's next generation reservoir simulator, EMpower.™,3 Multiple scenarios, including various injection patterns, scaleup methods, and locations of thin, high-permeability streaks, were investigated. Results mimicked known behavior in analogous producing fields and the process of going from rock data to simulation provided a useful training tool for reservoir characterization methods and techniques.
Expandable Tubular Completions for Carbonate Reservoirs
Authors: Marketz F. , van Noort R. H. J. , Baaijens M. N.
Published: December 2007

Expandable tubular solutions have been developed and applied as a drilling solution to extend well depth while maintaining a larger borehole diameter [1]. In this paper we review the benefits of expandable tubulars for shut-off and zonal isolation in carbonate reservoirs. Particular emphasis is given on a major Middle East Operator's experience.

Expandable open hole liner (OHL) systems, developed as a drilling solution, is based on expanding a liner across an open hole section and into the previous casing to form a liner hanger [2]. Instead of cement, elastomer seals provide zonal isolation in open hole [3], [4]. The liner is expanded to create a seal by energizing an elastomer between casing and the formation. In addition the elastomer swells in contact with water. This dual sealing mechanism provides an annular seal of any desired length. The technology is non-invasive on the reservoir. Alternative technologies either are invasive on the reservoir or have had limited success, i.e. cement, chemical squeezes or scab liners.

Expandable tubular solutions have proven successful in terms of installation reliability, isolation of fractures, swept zones and ghost holes. Also, the technology enabled inflow profile control through zonal isolation in horizontal wells. Case histories for shut-off and zonal isolation demonstrate the viability of extending the scope of expandable technology deployment for better management of carbonate reservoirs through a "drill, monitor & intervene" completion philosophy combining selectivity and shut-off in a low-cost intelligent completion solution.
A Turbine Flow Meter for Multiphase Flow
Authors: Li Zh.Y. , Kitami H. , Kawaoto H. , Watanabe T.
Published: December 2007

This paper introduces a new concept and the test result of a multiphase flow meter (MPFM), which JOGMEC (Old JNOC) and OVAL Corporation have developed based on a turbine type flow meter to measure the multiphase flow rate of individual phases in oil, water and gas production lines without the need for separation or complex sensor technologies (1)(2).

It is expected that the MPFM should bring a significant cost-down and improved operability and maintainability, compared with commercially available the turbine type MPFM in terms of nuclear-absorption type density measuring.

We had adopted integral calculus method and established a mathematics model.

In addition, we have examined the characteristics of the MPFM using a number of liquids with different viscosities (1–20mPa.s).

The test result shows that the volumetric flow rate of each phase are possibly measured with an uncertainty within ±10% of full range of the water cut and the gas void fraction varies from 30 to 90%. To confirm the MPFM reliability, MPFM monitoring was done for one year in an oil reservoir with water flooding in the wellhead platforms in Middle East. The MPFM measurement system can obtain enough accuracy to measure flow rates in each phase.
Evaluation of Coriolis Meters and Gas Flow Computers for Well Testing
Authors: Al-Saqabi Mishari , Kahali Kishore , Al-Kandari Ibrahim M.
Published: December 2007

Accurate and timely welltest data is critical to evaluate well performance and for effective reservoir management. In Kuwait Oil Company's Burgan South and East areas, the standard method of welltesting in the past has been through test separators and test tank. Because of the flow rate stabilization time and minimum volume required in the test tank for accurate reading of fluid level, welltest duration can range from 10 to 24 hours, especially for low volume wells. This is an operational challenge from the standpoint of acquiring accurate data and meet welltest frequency targets.

In an effort to meet these goals, KOC has installed a new system of well testing with Coriolis meter and AGA Gas flow meters in its gathering centers (GCs). The coriolis meter, an online mass and density flow meter, can measure well flow rates with reasonable accuracy within 1–2 hours.

This study has compared "simultaneous" well tests results of different categories of wells – high and low flow rate, dry and wet and high GOR using the Coriolis meter, GC test tank and portable test separator at the well. The performance and accuracy of this technology of well testing under different flow conditions are reported.
Sour Gas Development – Technical and Operational Integrity Issues and Management
Authors: Kamath A. R. Ramachandra , Milligan Michael , Dorp Johan van , Morsi Kamal , Szklarz Karol , Rippon Ian
Published: December 2007

Technical & operational integrity issues and their resolutions are dealt with leading to the concept selection for a high H2S (33% H2S) gas development in Abu Dhabi. Two strategic principles underpinned the concept selection and field development plan: (1) minimise Health, Safety and Environment (HSE) risks and (2) employ field proven technology and practices as far as practicable. Sulphur production instead of acid gas injection was rejected as a viable development option due to its environmental impact and the poor prospects for sulphur marketing. Developmental technical issues included sulphur precipitation in the production tubing and pipelines, and material selection for the sour gas well completions and the gathering & injection pipelines. Materials selection was based on designing out all catastrophic failures and corrosion mitigation & monitoring of progressive corrosion failure mechanisms. Operational issues were related to minimal facility manning and competence assurance of sour gas operatives.
New Analytical Solutions for 1-D Multicomponent Gas Injection Problems
Authors: Bedrikovetsky P. G. , Shapiro A. A. , Pires A. P.
Published: December 2007

Analytical models for 1-D displacement of oil by gas have been developed during the last 15 years. It was observed from semi-analytical and numerical experiments that several thermodynamic features of the process (MMP, key tie lines, etc) are not dependent on transport properties. After change of independent variables, the compositional (n-1)*(n-1) model for n-component flow is divided into a thermodynamics auxiliary (n-2)*(n-2) system and one transport equation. Explicit projection and lifting procedures are derived. The new technique developed permits splitting for both self-similar continuous injection problems and for non-self-similar slug injection problems. New different solutions for non-self-similar problems of gas injection in oil reservoirs are presented. With respect to 3-D flows, splitting takes place only for the case of constant total mobility (where the stream line concept is valid). For the general case of the total mobility variation, mixing between fluids that enter different streamlines occurs, and splitting does not happen any more.
Techniques to Aid Rapid Detection of High Permeability Conduits and Barriers in Reservoirs
Authors: Carnegie Andrew
Published: December 2007

Techniques based upon proportion curves and event analysis can greatly aid rapid detection of possible high permeability conduits and/or barriers in reservoirs. The techniques can use both dynamic data such as production rates and monitoring logs as well as static data such as open hole well logs. A recently created interactive PC software package allows effective application of these techniques. An example is presented of how the techniques greatly accelerated the history match of a heterogeneous carbonate reservoir by improving the calibration of open hole permeability log predictors by dynamic data, and allowing the conduit and barrier structure to be largely understood before full field history matching stage.

Suggestions are made on when and how to generally apply these techniques. It will be suggested that such techniques can supply inputs for distribution methods, such as Indicator Kriging and Truncated Gaussian Simulation, and thereby significantly enhance them. Other unconventional, yet useful applications of proportion curves will be mentioned, such as monitoring the changes being made in large flow simulation models during history matching, and determining areas where further data acquisition might be useful.
Correlation of the Upper Dalan/Kangan Formation between offshore Iran and the Zagros: Impact of lateral changes in facies and diagenesis on reservoir quality
Authors: INSALACO Enzo , LESCANNE Marc , MASSE Pierre , WALGENWITZ Fredéric , SUDRIE Marina , THIRY-BASTIEN Philippe , ROUMAGNAC Alain , FRAISSE Christian , KAMALI Mohammad , MOALLEMI Ali , LOTFPOUR Masoud , MONIBI Saeed , GAILLOT Jérémie
Published: December 2007

The Dalan/Kangan (Khuff) Formation is a major reservoir in Iran and the rest of the Middle East Gulf region, and contains some of the world's biggest gas reserves. The reservoir facies of this formation developed on a very large regional carbonate platform which had a very low topographic relief. This large geographic extent of the platform system is responsible for the development of very extensive facies tracts - in order to encounter major facies changes, large areas need to be investigated. This is often not possible in detailed reservoir-scale studies. In such cases, integrated models that extend from proximal positions to more oceanward locations are difficult to apply.

In order to address these issues a large multidisciplinary and multiscale subsurface study has been launched on a large database including fields from onshore and offshore Iran. The aims to better understand the facies distributions, sequence stratigraphic architecture and the regional reservoir development.

Twenty-two principal facies have been recognized including massive to laminated anhydrite, mudstone with anhydritic nodules, dolobreccias, green shale, massive to bioturbated mudstone, laminated dolomudstone, coarse lithoclastic and bioclastic grainstone, bioclastic grainstones, oolitic grainstones, peloidal grainstones, dark mudstones, and thrombolitic limestone. These facies have been interpreted in terms of depositional environment including: evaporitic flats or saltern (shelf supratidal/intertidal to subtidal setting), tidal flats (intertidal to supratidal setting, with numerous subenvironments such beach ridges, intertidal flats, tidal channels), subtidal lagoon (subtidal setting), leeward shoals (subtidal to intertidal setting), oolitic to oobioclastic shoal belts (subtidal to intertidal setting), composite sandwave constructions (subtidal setting), and middle shelf deposits (subtidal setting).

From the Dalan K4 through to the Kangan K1 significant changes in platform type/geometry, facies organization and climate occurred. Consequently, different depositional models need to be created for each of the major stratigraphic interval. Conceptual geological models have been constructed for the large-scale stratigraphic architecture, sedimentological organization and the palaeoecological systems. The correlations show significant changes in sedimentological and reservoir facies across the study area, which are not evident at smaller scales. These large-scale geographic and stratigraphic facies trends provide a regional framework which can then be used to help constrain reservoir-scale studies.
Historical Review and Rock Mechanics Approach to Improve the Wellbore Stability in Nahr Umr Shale Formation
Authors: Yamamoto K. , Waragai T. , Kikuchi S. , Fada'q A. S. , Koyama T. , Matsunaga T.
Published: December 2007

In this paper, the historical review for the drilling troubles encountered in the Nahr Umr (N.Umr) shale formation and the rock mechanics approach to improve the wellbore stability are described. An integrated approach is adopted for this study including the historical review for the actual drilling practices implemented to date, the studies of geomechanics, rock mechanics and chemistry for the N. Umr shale formation.

The historical review is performed based on the actual drilling data from year 1991 to March 2004.

The geomechanics model is determined with the data from the N. Umr shale formation and adjacent reservoirs. Logging data and collected formation sample data i.e. cores, cuttings are utilized to measure the properties of the formation. Numerical models considering the anisotropy and poroelastic nature of the shale lead the quantification of the failure mechanism.

Laboratory testings are conducted to analyze the basic chemical properties of the shale, and the interaction between the shale and mud. A newly produced testing apparatus is applied to determine the shear strength change of the shale under saturated condition with mud. Scanning Electron Microscope is utilized to ensure the failure mechanism and evaluate the validity of the shale inhibitors.

In this paper, the outline of the approaches is shown with some details of the testing and analysis methods.
4D Feasibility and Calibration Using 3D Seismic Modeling of Reservoir Models
Authors: Toinet Sylvain
Published: December 2007

Monitoring fluid motions in a producing reservoir is a key to understand reservoir behavior and anticipate drilling decisions and investments. In a deep-water environment such as Girassol (Angolan deep water, West Africa), the cost of a 4D seismic is less than the cost of a well, and 4D seismic is expected to provide the necessary monitoring information in terms of saturation and movement of fluids. Meanwhile, before deciding to repeat a 3D acquisition, the main question to answer through a feasibility study is: will the dynamic changes occurring in the reservoir be visible on seismic data? To achieve the 4D feasibility study, a reservoir model representing the state of the reservoir before production/injection, and another reservoir model after a certain time of production/injection were built. 3D Pre-stack synthetic seismic responses of the models were then computed in time and in depth using a fast algorithm accounting for fine-scale details of the reservoir model. Average amplitude maps extracted at key horizons, from the difference between 3D synthetic seismic responses of the two reservoir models showed the anticipated lateral extent of injection and production, and the impact in terms of amplitudes of the different injection and production mechanisms. These results of the 4D feasibility made us confident in the fact that the forecasted 3D seismic acquisition would provide important information about the reservoir dynamic characteristics. Since this work has been conducted, the new 3D seismic data that have been acquired. The identification and understanding of the differences between real and synthetic data helped us qualitatively and quantitatively to update the reservoir model and the petro-elastic model.
Porosity Heterogeneity Analysis Using Geostatistics
Authors: Gyllensten A. , Tilke P. , Al-Raisi M. , Allen D.
Published: December 2007

High levels of heterogeneity in many carbonate fields have raised concerns about the validity and relevance of small-scale measurements from core plugs and high-resolution logs. Although the measurements may be precise, they may not accurately describe average formation properties. A related question is one of reconciling the variability observed in small volume-of-investigation data (e.g., core plug), with the variability in relatively large volume-of-investigation measurements (e.g., wireline logs).

In a recent study of early Cretaceous carbonate reservoirs in Abu Dhabi, we developed a technique to address this issue using high-resolution borehole imaging logs. The resistivity image is first transformed into a porosity image using Archie's equation. The resulting porosity variability is then analyzed using geostatistics. This analysis allows us to extract geostatistical parameters (range and sill) at the scale of the borehole image measurements (0.1 in.) that provide a heterogeneity index for the rock.

We found that the scale of the heterogeneity is sufficiently small (typically less than 1 in.), such that significant heterogeneity will be observed at the core plug and smaller scales of measurement, while the impact on larger-volume logging tool response is minimal.

The fact that standard wireline logs are insensitive to most of the "heterogeneity" in these formations explains the difficulties in determining reservoir rock types (RRTs) from standard logs, because the properties distinguishing the RRTs from one another (macrofossils and molds) are present at a scale below the sensitivity of standard logs. In contrast, properties measured by the logs can be expected to reflect the larger-scale reservoir properties around the well.

These findings have significant impact on how we calibrate logs using core data and how we should upscale reservoir properties derived from core and log data in our 3D earth models.

The findings support our recommendation to use core plugs larger than the conventional 1-in. plugs in carbonate formations to ensure that the small-scale heterogeneities are captured within the core plug itself.
Four-Phase Streamline-Based Compositional Simulation of Gas Injections for a Viscous Oil
Authors: Li Dacun
Published: December 2007

Because it is extremely time-consuming to run compositional simulations, people tend to use fewer components, or fewer grid blocks, or both. However, the use of fewer components leads to inaccurate phase behavior while application of fewer grid blocks causes larger numerical dispersions. When the reservoir temperature is lower than 120 °F and pressure is lower than 1500 psia, gas injections, especially when injectants include CO2, may result in four phases: water, oil, gas, and the second non-aqueous liquid. In this paper, a streamline simulator is developed and found to be able to be used to model the four-phase flow for the 9-component injection of 50-50 combination of Prudhoe Bay Gas (PBG) and Natural Gas Liquid (LNG) into a reservoir with 12-component viscous Shrader oil. Results indicate that the streamline simulation is many times faster than finite-difference simulation. In addition, viscous fingering is sharply caught by streamline simulation while the displacement front is very blurry in finite-difference simulation due to high numerical dispersions.

The streamline simulator can be used for gas injection problems with up to four phases.
The Upper Khuff formation, sedimentology and Static Core Rock Type approach - Comparison of two offshore Abu Dhabi fields
Authors: Meyer A. , Boichard R. , Azzam I. , Al-Amoudi A.
Published: December 2007

A study focused on the sedimentology framework and on the Static Core Rock Type determination has been carried out on the Permo-Triassic upper Khuff reservoir formation in order to improve the full field reservoir models of two Abu Dhabi Offshore gas fields.

The comparison of results indicates that the Khuff formation can be described by twelve lithofacies corresponding to five main depositional environments ranging from sabkha to oo-bioclastic shoal. The sequence stratigraphy evolution of these depositional environments leads to establish a fine scale reservoir layering, which evidences a large extent of the defined lithofacies between the two investigated fields. The limit between the Permian and Triassic series has also been defined. The results obtained from the sedimentary setting between these two fields provide important keys for further sedimentological and reservoir layering studies regarding other Abu Dhabi fields.

Eighteen Static Core Rock Types have been defined by combining lithology, lithofacies, pore type association and petrophysical properties (K, PHI, MICP). If three major Core Rock Type groups can be easily differentiated (Limestone, Fabric-Selective and Non Fabric Selective Dolomite), some differences related to the diagenesis intensity, especially the dolomitisation process and the late anhydrite precipitation, exist between the two fields. Consequently, the lateral extent of the Core Rock Types can be very variable within a defined reservoir layer. Mapping the Rock type variations requires both, full analysis and integration of all sedimentological, diagenetic and petro-physical data in order to better constrain a 3D full field model.
Deliverability of Wells in the Gas Condensate Reservoir
Authors: Du Y. , Guan L. , Li D.
Published: December 2007

Underground flow in gas condensate reservoirs usually consists of single-phase gas flow at initial reservoir conditions (reservoir pressure Pr larger or equal than dew point pressure Pd). However, with the depletion of the gas condensate reservoir, when its flowing bottom-hole pressure of a producer falls below the dew point pressure of the corresponding reservoir fluids, a relatively high liquid saturation will build up near the wellbore, which is named as "condensate blocking".

The formation of this "condensate blocking" in the near-well region will lead to the reduction in gas relative permeability and result in loss of well deliverability. This deliverability loss is also indicated by the field production data from many gas condensate wells. In this paper, this loss is investigated by conducting a series of fine-grid numerical compositional simulations with the reservoir data. The well deliverability index (PI) at initial reservoir pressure, slightly above dew point pressure for a single-phase gas flow was found to drop rapidly due to condensate banking. The gas PI at a reservoir pressure equal to half of dew point pressure is only about 20% of the value at a reservoir pressure, slightly above dew point pressure for low permeability cases (permeability less than 100md).

We also found that PVT properties of reservoir fluids, absolute permeability, and production pressure drawdown of the producer all have significant influence on the well gas deliverability.
Direct Application of Geopyphiscal/Seismic Methods for N/G Calculation
Authors: Vanaki Mohammadreza , Sede Bahman Samimi , Behzad Ramin
Published: December 2007

There are several methods for Net/Gross calculation by seismic methods which are as follows:

-AVOprocessing and Attribute analysis for lithology and pore-fluid detection on seismic data:

Amplitude versus offset is one of important method for detect anomalies associated with presence of hydrocarbons in the subsurface.

-Elastic parameter:

In this method P-wave velocity (Vp), S-wave velocity (Vs) and bulk density should be caculated. Then Vp/Vs ratio to be calculated by these parameters.after that Poisson's ratio, bulk modulus, rigidity modulus, Lame's constant, Young's modulus can be calculatedby Vp/Vs ratio.This parameters indicate the kind of litho logy and shale content. At last the porosity of reservoir can be calculated by these parameters.

-Seismic attributes:

One of the most important seismic attributes for calculating N/G ratio is amplitude. Gross porosity and fluid content could be given by amplitude analysis.

Instantaneous is the seismic attribute that has important rule in N/G ratio calculation.litho logical contrasts and fluid content could be resulted by this attribute.

In this paper we will explain above methods then we will calculate N/G by elastic parameter in a field with real data.

At last we will compare results of this method with petrophysical method.
Pressure and Pressure Derivative Analysis for Linear Homogeneous Reservoirs without using Type-Curve Matching
Authors: Escobar Freddy H. , Saavedra Nestor F. , Hernández Claudia M. , Hernández Yuly A. , Pilataxi Juan F. , Pinto Diego A.
Published: December 2007

A significant number of well pressure tests are conducted in long, narrow reservoirs with closed and open extreme boundaries. It is desirable not only to appropriately identify these types of systems but also to develop an adequate and practical interpretation technique to determine their parameters and size, when possible. An accurate understanding of how the reservoir produces and the magnitude of producible reserves can lead to competent decisions and adequate reservoir management.

So far, studies found for identification and determination of parameters for such systems are conducted by conventional techniques (semilog analysis) and semilog and log-log type-curve matching of pressure versus time. Type-curve matching is basically a trial-and-error process which may provide inaccurate results. Besides, a limitation in the number of type curves plays a negative role.

In this paper, a detailed analysis of pressure derivative behavior for a vertical well in linear reservoirs with open and closed extreme boundaries is presented. We studied independently each flow regime, especially the linear flow regime since it is the most characteristic "fingerprint" of these systems. We found that when the well is located at one of the extremes of the reservoir, a single linear flow regime develops once radial flow and/or wellbore storage effects have ended. When the well is located at a given distance from both extreme boundaries, the pressure derivative permits the identification of two linear flows toward the well and we called that "dual-linear flow regime". This is characterized by an increment of the intercept of the ½-slope line from π0.5 to π with a consequent transition between these two straight lines. The identification of intersection points, lines, and characteristic slopes allows us to develop an interpretation technique without employing type-curve matching. This technique uses analytical equations to determine such reservoir parameters as permeability, skin, well location and reservoir limits for both gas and oil linear reservoirs. The proposed technique was successfully verified by interpreting both field and synthetic pressure tests for gas and oil reservoirs.
Numerical Welltest Analysis
Authors: Nnadi Magnus , Onyekonwu Michael
Published: December 2007

The importance of reservoir and well parameters estimated from BHP analysis, has made it necessary to analyze field pressure data as practically as possible. This has lead to the application of numerical solutions to BHP analysis. It involves the proper griding of reservoir and subsequent numerical solution of the resulting partial differential equation. This incorporates heterogeneity of reservoir properties into BHP analysis, thereby broadening its applicability to reservoir description, unlike analytic solution, which does not offer the details it requires.

Although, analytical methods give reasonable estimate for simple cases, they are not suitable for real complex cases, due to the limiting assumptions inherent in their development.

This paper assessed the applicability of numerical solution to BHP analyses. It solved some field examples analytically and numerically, first for a known simple case and then for real complex cases. Furthermore, test design data were generated using field data in a heterogeneous system. The test was analyzed using both analytical and numerical approaches. The results obtained show that although analytical solutions can be employed for some heterogeneous systems, they are highly idealistic and limited to some convenient cases and that numerical solution models field data realistically.
Information Management in E&P - the Shell Nigeria Experience
Authors: Peterson Tim , Oluwole Olubunmi , Akano Tonie , Olatinwo T. K.
Published: December 2007

In Shell Petroleum Development Company Nigeria Limited, SPDC, the business of Exploring and Producing Hydrocarbon relies a great deal on the provision of adequate and proper information for the day-to-day activities. This paper will focus on how the subsurface communities business activities have been enabled by the provision of the right information and the underlying Information Technology. This has been highly effective due to the setting up of special IM (Information Management) organizations to

identify the information needs of the professionals responsible for the finding/producing new hydrocarbon. proffer the most appropriate and cost effective Information Technology develop the annual IM business plan acquire and deploy the fit-for-purpose Information Technology tools and train the professionals in the use of these tools.

The themes of this paper are as follow: Data and Document ManagementIntegration, Collaboration & Workflow InitiativesOptimization of IM PortfolioGlobalization of IM Tools & ProcessesTraining the CustomersHealth, Safety, Environment & Security

Some key technologies, recently deployed, will be show cased.
Acoustic Sand Monitor Trials in the Offshore CVX-NMA: Results and Lessons Learned
Authors: Fariyibi F. L. , Umurhohwo J. O. , Olson S. G. , Scott K. C
Published: December 2007

Several of the Offshore CVX-NMA wells have been produced on small choke sizes from a concern about sand production. A review of the historical impact of such constraint showed a significant production loss in the past ten years. Looking into the future, nodal analysis has shown that by producing some of the wells on small choke sizes, they can pre-maturely load-up and die, and in some cases producing high GORs due to choke restriction. Also some of the fields in the offshore locations are at their mature stage with increasing water cuts, thereby susceptible to "higher than normal" sand production.

A Pilot acoustic sand monitoring was, therefore carried out to validate sand production rates and test opportunities to "un-constrain" wells by opening chokes and increasing oil rates. Plans were developed for deployment, training and monitoring. The team made critical decisions in selecting choke sizes during the trials and documented results.

This paper presents the results and lessons learned from the field trials in the Offshore areas of CVX-NMA The exercise proved the effectiveness of sand detector technology to diagnose the severity and characteristics of our sand production and enhance the practise of Operational Excellence in a timely manner. The first phase of the Field trials yielded a total production gain of ~ 3,300 bopd. Long term gains expected include decrease in OPEX (choke replacement, CTU cleanout, Operations vessel cleanouts etc).
Production Optimization using Genetic Algorithm Approach
Authors: Tavakkolian M. , F. Jalali F. , Emadi M. A.
Published: December 2007

The objective of the research presented in this paper is to investigate the effectiveness of "Genetic Algorithm " technique in optimising the performance of hydrocarbon producing wells.

The performance of a production well is a function of several variables. Examples of these variables are tubing size, choke size, and separator pressures. Changing any of the variables will alter the performance of the well.

The advantages of nonlinear optimization methods are many. Using nonlinear optimization techniques, there is no limit to the number of decision variables that can be optimized simultaneously.

Through this paper, a new method for analysis of an oil and gas condensate production system is presented. This method is a new stochastic method which enables us to analyze a system of mathematical equations containing a great number of decision variables and determine the optimum values of them, that should give the most economic result. The presented method is referred to as "Genetic Algorithm" (GA). Here a mathematical model approach is initially applied for the well and surface facilities and then the result is analyzed and further optimized to enhance profitability.

The production facilities considered in this paper consist of tubing, choke, and separators. The method applied is able to consider dual sized tubing (combination of tubing and casing). Furthermore, it is able to determine the optimum number of separators.

The developed code in MATLAB environment, based on GA, is able to obtain the most optimum size(s) for the tubing (single size or dual sized tubing), the depth at which the tubing size should vary (in case dual sized tubing is selected), choke size, number of separators, and separator pressures. The optimisation of these parameters should result in improved hydrocarbon liquid production.

Finally, this method and the developed code have been applied to the production system of a real oil field and the obtained results have been compared to those of Prosper simulator. The results show that GA is a powerful tool to analyze the production system of hydrocarbon fields.
Well Integrity Management in Shell Nigeria
Authors: Wakama Miebaka , Eta Edirhin , Adeniyi Ade
Published: December 2007

Well Integrity is a vital aspect of well design, construction, operation, maintenance and abandonment. As put by SPDC, "all wells shall be designed, constructed, operated, maintained and abandoned in a manner that safeguards their integrity, minimize Health, Safety and Environmental risks and ensure their planned availability throughout their life-cycle". As a consequence of this policy, all wells are monitored to ensure their integrity is guaranteed at all times. By implication all wells that fall short of standards are secured or closed-in unless a short-term deviation or waiver is granted.

Well integrity problems may occur in producing and non-producing wells, especially older wells that were completed as per the prevailing completion standard of their completion dates. The completion standards have changed over time with respect to safety requirements (e.g. wells without top packers, wells without SCSSVs). There may also be some wells that meet current safety standards but still have some integrity-related problems (e.g. leaking packer or silted well slots-swamp locations).

Although, the necessity to enhance the integrity of wells is recognized, enhancement activities have been limited by past budget constraints. The identified activities often rank low in oil generating economics when compared with other projects within the portfolio competing for funds. It therefore became necessary to effectively manage the wide range of well integrity problems, by adopting a concept of ‘Well Integrity Management System ’. In 2003 a dedicated team was set up to assemble a coherent process from the practices of the past and the present and inventorise work that needed to be carried out to ensure that well integrity issues are being adequately addressed.

This paper discusses the initiative by SPDC, Nigeria to put in place a Well Integrity Management System (WIMS) and successes so far.
Productivity Enhancement through Single Well Numerical Modeling
Authors: Ezuka I. O. , Egbele E. E. , Harcourt Port , Onyekonwu M. O.
Published: December 2007

There have been many different aims, relevance and results justifying single well study. Yet little or none has been said about its relevance in production enhancement

Single well modeling is the act of using numerical reservoir simulation equation to study well performance. It is very insightful in evaluating completion strategy, study coning/cusping behavior, well reserves, and relative permeability pseudo-functions for wells in full field models, complex pressure transient data analysis and well economics. This paper presents the applications of single well modeling in productivity enhancement.

The productivity of a well is going to be modeled by using the numerical simulation equations coupled with well production parameters. A combination of several production strategies will be evaluated. Having matched the well model, the combination and strategy that gives the optimum production from the well is to be recommended. The advantage of this is that it couples the reservoir conditions, near wellbore fluid distribution, near wellbore reservoir description, production mechanism with completion strategy to predict well performance. The matched model with a level of uniqueness can predict the well performance to an acceptable level of accuracy.

The challenge of handling excess water production and its impact on the overall well productivity can met through Single Well Numerical Modeling. Single well modeling can be used to determine the optimum well operation and production approach.

The result of the numerical modeling indicates that Single Well modeling is a powerful tool for production enhancement. In water cusping cases, the best strategy for maximum recovery from the well is to avoid early water breakthrough. Re-perforation is not the best economic solution for a well experiencing water cusping. It is a good practice to numerically simulate a well to determine its cone and cusp free rate prior to production. This will aid to archive maximum recovery from the well. Single Well modeling is a good tool for Well economic analysis.

A case study of two wells that penetrated a Niger Delta reservoir will be used.
Prediction of Critical Foam Velocity for Effective Cuttings Transport in Horizontal Wells
Authors: Li Yibing , Kuru Ergun
Published: December 2007

A mathematical model and a numerical analysis of the cuttings transport with foam in horizontal wells have been presented earlier. The model has been incorporated into a computer program and used for finding a closed form critical foam velocity (CFV) correlation.

The new CFV correlation can be used to predict minimum foam flow rate required to remove, or prevent the formation of stationary cuttings beds on the low-side of the highly deviated and horizontal wells.

Effects of key drilling parameters (i.e. drilling rate, annular geometry, foam quality, bottomhole pressure and temperature) on the critical foam velocity have also been investigated.

Numerical examples are presented to illustrate how the CFV correlation can be used to determine required gas and liquid flow rates at the downhole conditions