bluuebunny/crossref_metadata_2025 huggingface dataset:
Modeling Naturally Fractured Tight Carbonate Reservoirs – A Case Study
Authors: Chakraborty Subrata , Narahari Srinivasa Rao , Al-Ajmi Neama Hussain , Al-Ashwak Samar , Kidambi Vijaya Kumar , Pattnaik Chinmaya , Stelzer Hermann
Published: September 2011

Kuwait Oil Company (KOC) is engaged in an early phase of development of a giant, tight, fractured carbonate play within the State of Kuwait, spread over a large area covering six fields. The producing reservoirs belong to the geological Formations of Toarcian to Tithonian age. Some reservoirs are characterized by very low porosity and permeability and productivity of these reservoirs is driven by the natural fracture system. This paper described the approach followed in developing a 3D fracture model for these reservoirs.

Carefully planned data acquisition resulted in a rich suite of dataset consisting of image logs, conventional cores covering the target pay zones in a number of wells. Analysis of these data gave a clear understanding about fracture orientation, density, aperture, and other fracture parameters. Special 3D seismic processing was carried out to derive a volume curvature attribute, which was able to detect and identify the fracture corridors away from the wells. Structural geological analysis resulted in an understanding of the tectonic history of the area, which helped in genetically relating the identified fracture orientations with the structural evolution. A discrete fracture network was developed for these reservoirs combining the well and seismic attribute data. Parameters like aspect ratio, orientation and aperture of fractures was assigned to different fracture sets based on this analysis. The apertures were corrected for the present day stress effect based on the borehole breakout data. This fracture model was upscaled into the 3D geological model to get the fracture porosity and the permeability tensors. The fracture model was validated by history matching pressure build up and production data and was used for dynamic flow simulation studies for the field development planning.
An Easy-to-Use Matlab-based Computer Program for Prediction of n-Alkanes Surface Tension
Authors: Bahadori Alireza , Vuthaluru Hari , Bahadori Meysam
Published: September 2011

One of the most striking demonstrations of intermolecular forces is the tension at the surface of liquid n-alkanes. The prediction of surface tension is important in the design of distillation towers, extraction units and tower internals such as bubble caps and trays, since it has a considerable influence on the transfer of mass and energy across interfaces. Surface tension data are needed wherever foaming emulsification, droplet formation or wetting are involved. They are also required in a number of equations for two-phase flow calculations and for determining the flow regime. Petroleum engineers are especially interested in the surface tension in the extraction of crude oil to add surfactants to modify the interfacial properties between crude oil and the geological reservoir to improve production and increase oil yields. In this work, a simple computer program using Arrhenius-type asymptotic exponential function, Vandermoned matrix and Matlab technical computing language, is developed for the estimation of surface tension of paraffin hydrocarbons as a function of molecular weight and temperature. The surface tension is calculated for temperatures in the range of 250 to 440 K and paraffin hydrocarbons molecular weights between 30 and 250. The proposed numerical technique is superior owing to its accuracy and clear numerical background, wherein the relevant coefficients can be retuned quickly if more data become available in the future. Estimations are found to be in excellent agreement with the reliable data in the literature with average absolute deviation being less than 2%.
The Modification of the Dykstra-Parsons Method for Inclined Stratified Reservoirs
Authors: El-Khatib Noaman A.
Published: September 2011

The Dykstra-Parsons method is used to predict the performance of waterflooding in non-communicating stratified reservoirs. Much interest was shown lately for the application of the method for chemical flooding and in particular for the case of polymer injection used for mobility control. The original method however assumes the layers to be horizontal. Most oil reservoirs exhibit a dip angle with the water being injected in the up dip direction. It is there for important to account for the effect of the inclination on the performance.

A modification of the Dykstra-Parsons equations is obtained to account for reservoir inclination. The developed model includes a dimensionless gravity number that accounts for the effect of the dip angle and density difference between the displacing and displaced fluids. The derived equation that governs the relative locations of the displacement fronts in different layers is non linear and include a logarithmic term. Iterative numerical solution is used to obtain the location of the front in the different layers at the time of water breakthrough in successive layers. This solution is used to obtain values for the fractional oil recovery, the water cut, the dimensionless time and the injectivity ratio.

Solutions for stratified systems with log normal permeability distribution were obtained and compared with the horizontal systems. The effects of the gravity number, the mobility ratio and the Dykstra-Parsons permeability variation coefficient (VDP) on the performance are investigated.

It was found that the gravity (dip angle) enhances the performance in terms of delaying water breakthrough, increasing the fractional oil recovery, and decreasing water cut as compared to horizontal layers. This occurs for both favorable and unfavorable mobility ratios but is more evident in unfavoorable mobility ratios and more heterogeneous cases.

The results were also compared with the performance of inclined communicating reservoirs with complete crossflowand the communication was found to improve fractional oil recovery for unit and favorable mobility ratios and decrease recovery for unfavorable mobility ratio.
Solid Expandable Solution for Wellbore Stability in Developing Khafji Offshore Field
Authors: Kumamoto K. , Qadmani Marwan Ahmad , Hanak Hrvoje , Sanders Tom , Harvey Michael , Saad Marc-Antoine
Published: September 2011

Development of existing mature fields can pose a wide variety of specific challenges originiating from earlier programs and extended production operations. Wellbore stability parameters can change as fields mature and wells age requiring suitable combinations of innovative techniques and new technologies to further develop these fields. Added challenges arise when the development program is based on re-entering existing wells.

Al-Khafji Joint Operations (KJO) is developing and producing the offshore Al-Khafji field, located in the former offshore neutral zone between Saudi Arabia and Kuwait. The field has commenced oil production in 1961.

To sustain and meet the increased production targets, the operator started implementing a novel drilling and workover project. The program was designed to mitigate expected challenging borehole instability problems in the Wara and Burgan shale formations, resulting in issues such as stuck bottom-hole assemblies, poor hole enlargement and cleaning, and poor deviation control. The instabilities are encountered in the build sections of the horizontal wells and are further complicated in re-entry wells, due to the limitation is casing string sizes from surface. The novel program implemented incorporated an optimized drilling fluid system and a solid expandable open-hole liner that was utilized to case off these unstable formations and allow the well to be drilled without downsizing the planned production zone size and compromising well objectives.

This paper details the extensive studies and planning, originating from lessons learned that were implemented in the integrated program with focus on the innovative techniques and new technologies used in this field. Specific focus is placed on the solid expandable system used as it formed an integral part of allowing a successful implementation of these programs.
To ICD or Not to ICD? A Techno-economic Analysis of Different Control Strategies Applied to a Thin Oil Rim Dield Case
Authors: Twerda A. , Nennie E. , Alberts G. , Leemhuis A. , Widdershoven C.
Published: September 2011

During end-of-life production from an oil well it is often impossible to sustain continuous production. Gas coning is a common cause of production problems, especially in thin oil reservoirs. This study compares three production strategies that can be used to deal with this problem for a specific field case. The strategies will be evaluated on the basis of two criteria: Total number of barrels produced and Net Present Value (NPV). The three strategies considered are (i) intermittent production, (ii) Well Head Control (WHC), (iii) Inflow Control Devices, (ICD). The first two are currently common practice, while the latter is an emerging technology which is not applied on a large scale yet, because of the larger expense incurred by ICD installation.

The onset of gas breakthrough occurs in a much shorter timescale than many other production upsets, such as water flooding, making it a very challenging situation for a control strategy. A coupled dynamic reservoir-well model has been used in order to describe the breakthrough accurately. A simulation environment has been constructed and validated in which different well and reservoir models can be coupled. Since correct prediction of flow and pressure drop over ICDs is essential, special care was taken to accurately model these devices. For the WHC control strategies a Proportional Integral Derivative (PID) algorithm was used.

Despite the higher initial completion costs associated with ICDs, they can provide a cost-effective way to reduce long-term operating costs and increase yield. Production targets are achieved with longer, but fewer wells, maintenance and overhead. From a reservoir management point of view, ICDs can improve the productivity index (PI) by maximizing reservoir contact, minimizing gas coning by operating at lower drawdown, and increasing overall efficiency.

In this study we evaluate a field case, which suffers from gas coning, to verify whether the implementation and usage of ICDs are cost-effective alternatives, and quantify the relative merits for each technology. The comparison is based on both the total barrels produced and the NPV, taking into account the integral cost, including installation, operating, and maintenance costs.
Heavy Duty Wireline Fishing Operations in a HP/HT Sour Gas Well – A Case Study
Authors: Purwagautama Gustioro , Idi Yusuf A , Syahriza Ghany R. , Vincent John
Published: September 2011

HP/HT gas wells, especially those in South Sumatra, Indonesia, present many challenges to exploitation operations due to a 408°F bottomhole temperature, a 10,500psi bottom hole pressure at some 11,000ft, and sour gas components of 34% CO2 and 100 –200ppm H2S.

During the final stages of the completion of one such well, after setting the production packer a wireline run was made with .108″ slick line to recover the plug body from the seating nipple at 11.406ft. While pulling out and with the plug at 6000ft. the well became live without warning, blowing the tool string up the hole and, to contain the well, the drilling BOPs were closed shearing the landing joint which in turn closed the sub surface safety valve. Subsequently the well was successfully completed and prepared for wireline fishing operations.

The wireline fishing operation went on for several days using .108″ wire, during which 45 runs were made with the recovery of only approximately 550ft of wire and so it was decided to call in heavy duty wireline fishing (HDWF) expertise to review the situation and make recommendations as to how to proceed. This resulted in a commitment being made to mobilize personnel and equipment from Aberdeen and the Middle East to carry out the required operations. In the meantime a total of 11 further runs were made in the well using coiled tubing which resulted in recovery of the upper part of the tool string and some additional wire. Fishing operations were recommenced using 7/32″ Supa 75 braided cable with two two/man crews providing 24 hour operation and a project leader located at the clients office to provide for direct liaison. After a total of 17 runs over 6 days of continuous operation, the fish was completely recovered and the well made ready for production.

In this paper the authors will review the situation that was faced, the remedial work done to complete the well, the early fishing operations and the subsequent input of HDWF expertise. They will conclude with a detailed account of the successful HDWF operation – an excellent example of how careful planning, experienced personnel, dedicated project management and a collaborative relationship between the client and service company can lead to a successful outcome.
EoS Modeling for Two Major Kuwaiti Oil Reservoirs
Authors: Al-Ajmi Moudi Fahad , Tybjerg Peter , Rasmussen Claus P. , Azeem Jawad
Published: September 2011

Two fluids with extensive routine PVT and miscible gas injection EOR data from two different major Kuwaiti oil fields are presented. Eight component EoS models were developed for the two fluids using the volume corrected Soave-Redlich-Kwong equation of state.

A sensitivity study has been conducted on the routine PVT and EOR data for both fluids using multiple linear regressions. The critical temperatures and critical pressures were found to be the most sensitive parameters when modeling routine PVT data, while the EOR data was found to be more sensitive towards changes in acentric factors and binary interaction parameters.

Both routine PVT and EOR data was matched very well with the developed EoS models. With an accurate match of the critical points in the Swelling Test experiments and the near-critical compositions in the Equilibrium Contact and Multiple Contact experiments, the MMPs of the two reservoir fluids were matched very well predictively without further parameter adjustments.
Advanced Mud Logging Aids (AML) Formation Evaluation and Drilling, and Yields Precise Hydrocarbon Fluid Composition
Authors: Loermans Ton , Bradford Charles , Kimour Farouk , Karoum Reda , Meridji Yacine , Kasprzykowski Pawel , Bondabou Karim , Marsala Alberto
Published: September 2011

While traditional mudlogging techniques provide largely qualitative data, the prime objective of Advanced Mud Logging (AML) is to provide quantitative real time measurements in aid of a complete formation evaluation. To achieve this, wellsite mudlogging technologies have been enhanced, and various techniques which historically were limited to laboratories, have been adapted for well site usage. AML well site techniques thus include: (1) high frequency, improved accuracy monitoring of drilling parameters; (2) enhanced cuttings image acquisition and processing; (3) direct measurements on cuttings, including graindensity, spectral GR, NMR, XRD, XRF; and (4) sophisticated mud gas analysis capabilities.

We describe the main system components developed and present some results of the first pilot tests done in Saudi Arabia with AML techniques and a dedicated AML unit. Examples in the four areas mentioned above illustrate and confirm the potential of AML. On one special technology test well, different systems, from two different companies, were run in parallel to establish the merits and possible limitations of especially the hydrocarbon analysis systems.

One of the most striking examples of the quality of AML is a perfect match between the hydrocarbon fluid composition determined from mud gas returns, and those subsequently obtained from PVT measurements on wireline fluid samples. To achieve this, AML technology developers in the industry advanced across the whole process chain affecting such quantification. First and foremost, improving sample extraction and handling, combined with enhanced calibration procedures, to convert from in situ to surface conditions. Second, in addition to sampling both the return mud flow and the inflow, a more precise tracking of flowrates and system volumes was made possible with modern operating systems. Third, adding a mass spectrometer to the gas chromatograph, improved the final measurement potential.
Full Barrel Analysis: A Simulation Model Interrogation Tool to Assess Sweep Efficiencies and Identify Targets for Improved Oil Recovery
Authors: Beckman M. S. , Dickson J. L. , Harris C. R. , Frankel D. S.
Published: September 2011

A reservoir simulation post-processing tool, the Full Barrel Analysis, has been developed to assess sweep effectiveness and identify targets for improved oil recovery. The tool also quickly determines the potential for increased recovery via enhanced oil recovery methods or improved reservoir management. To perform these functions, the tool extracts information from simulation results and performs novel calculations using SAS®*. The calculations include sub-dividing the oil-in-place into eight categories, which are called ‘sections’ of the barrel, using a combination of cell binning and oil designation rules. The oil in the reservoir is then represented as a composite ‘barrel’, whose composition is represented by these eight sections. These sections used to describe this representative barrel are aligned with potential recovery methods, providing a fast and simple technique to screen reservoirs for recovery methods. The tool reports the volume of each section present in the composite barrel in a succinct format that can be easily interpreted by reservoir engineers and geoscientists. The binning and designation rules used to create the barrel sections allow the user to determine which areas of the field are under gas or water flood, the total immobile oil, the total non-economic oil and areas with improved reservoir management opportunities. In addition, the Full Barrel Analysis provides maps and 3-D data that are valuable tools to analyze the reservoir model for sweep performance, in-fill drilling opportunities, and QA/QC issues. The tool output is also useful for comparing development or geologic scenarios, giving insight into the impact on sweep effectiveness and future recovery potential via improved or enhanced oil recovery methods.
Optimization of Conventional Acid Jobs and the Historical Trend Leading to Multistage Acid Fracturing Stimulation to Increase Gas-Condensate Productivity in Carbonate Reservoirs in Saudi Arabia
Authors: Franco C. A. , Solares J. R. , Asiri K. A. , Al-Shammari N. S. , Alabbad E. A. , Gomez F. A.
Published: September 2011

The majority of the gas-condensate reserves, currently being developed from fields located in southern Saudi Arabia, come from tight carbonate reservoirs, which require acid stimulation to achieve gas rate targets and field development objectives.

Most of the gas producers drilled at the beginning of the gas development program were vertical completions, the majority of which were acid fractured and achieved excellent post-stimulation results. As the development scope expanded to areas with tighter reservoir characteristics, the majority of new wells were drilled as open hole single or dual lateral completions to achieve maximum reservoir contact (MRC). A significant number of these wells did not require acid stimulation, but many others did, either to increase productivity in underperforming wells, or to remove drilling induced formation damage. The most recent approach in the evolutionary process is to drill single lateral open hole horizontal producers and fit them with a completion designed for multistage fracturing treatments.

This recent approach has allowed Saudi Aramco to effectively stimulate the entire horizontal section, optimize treatment designs, and achieve excellent post-stimulation results and high gas rates from wells drilled in even tighter reservoirs. This paper describes the historical trend leading to the selection and implementation of multistage fracturing technology as a fit-for-purpose technology to maximize productivity in long horizontal gas producers, and shares post-stimulation results achieved in typical wells drilled and completed throughout the different development phases.
Robust Multi-Phase Flow Measurement Using Magnetic Resonance Technology
Authors: Appel M. , Freeman J. J. , Pusiol D.
Published: September 2011

A compact 3-phase flow meter based on Magnetic Resonance technology has been developed to the prototype stage, and tested in a commercial flow loop.

No single well head meter currently available on the market simultaneously satisfies the customer’s need for accuracy across a broad range of produced volumes and hydrocarbon properties, operational robustness, with low cost hurdle. Consequently, a large number of installations are either insufficiently metered or rely on accurate, yet costly and operationally cumbersome test separators. Insufficient metering may result in suboptimal reservoir management and uncertainty in allocation of co-mingled production.

This development targets provision of highly accurate, real-time quantification of flow rates for oil, water, and gas in multiphase flow. Magnetic resonance is intrinsically sensitive to flow; however, current applications to flow measurement are limited to very low flow rates that are inapplicable to oil-field applications. This meter employs a new principle that enables robust 3-phase flow metering with a broader operating envelope than existing flow meters, has no sensors in the flow stream, no radioactive source, yet could potentially be produced at sufficiently low cost to promote increasing numbers of well head installations. Results obtained at a commercial flow loop confirm a broad operating envelope, accurate 3-phase flow characterization, as well as direct measurement of phase slip.

This paper describes the technical design of the flow meter and presents measurements of individual phase instantaneous velocity and hold up, for all phases under full 3-phase flow conditions acquired in a commercial flow loop. The data includes a range of fluid properties and flow conditions.
Fluid Characterization, A Case Study of a Field with Compositional Gradient
Authors: Kalehbasti Mehdi Alipour , Paroodbari Javad Rostami , Ravari Reza Rostami , Amani Mahmood
Published: September 2011

The phenomenon of variation of fluid properties with depth has been observed in reservoirs with large thickness or high dip angle where primarily the gravitational forces along with the thermal effect play an important role on the overall composition of the system. Compositional grading is more evident in high shrinkage oils, volatile oils, rich gas condensates as well as the black oils. Compositional grading is a key issue in dynamic modeling of the reservoir and must be given enough care during both estimation of the stock-tank initially in place and reservoir performance.

This paper presents an engineering evaluation of fluid characterization of a heavy, viscous oil from an Iranian oil reservoir which is considered for a gas injection project. After screening of all available PVT data, the validated data were input into the PVT package and reproduced all existing experiments with only one EOS. Since there was no firm evidence of different equilibrium regions inside the reservoir, it was decided to have one EOS for the whole reservoir with varying mole fraction with increasing depth.

Viscosity is the main property to be predicted with EOS in this task. Mole fractions of C7+ are critical in this case and need special attention. For regressing experimental viscosity, two regions were defined. The results show that the suggested EOS will lead to a reasonable match of all experimental data and when was used in the reservoir simulation in the next phase of the project, the initial oil in place was close to that obtained based on previous black oil model.
World's First Hybrid Inflow Control Completion in India's Largest Onshore Oil Field
Authors: McKenzie Tim , Wenk Andrew , Khan Parvez , Gavioli Paolo , Andrew Colin
Published: September 2011

The Mangala oil field, onshore Rajasthan, India, is the country’s largest onshore oil producer. The field holds large reserves of high wax viscous crude which have a number of significant production challenges, one of which is an unfavourable oil/water mobility ratio.

The FM3 and FM4 sand units in the Mangala reservoir are being developed with horizontal wells and the well design required a completion to manage sand production and the adverse oil to water mobility ratio with a preference for minimal well intervention. These reservoir units are composed of thick high-permeability sandstones. It was recognised that field recovery and production rates would be optimised by the application of the most suitable technologies available in inflow control management.

This paper describes the successful implementation of the world’s first hybrid inflow control completion for a high wax viscous crude reservoir, including: the hybrid inflow control device selection, completion design and installation, and post-production logs which confirm the performance of this world’s first completion system.
Case History of the First Global Installation of a Gravel Pack System that Allows Continuous Pay Zone Chemical Treatment Pumping Without Interrupting Production
Authors: Surveyor Nilufer , Amaral Anderson , Pinto Marcela
Published: September 2011

Offshore wells, especially deepwater completions, are usually completed with semisubmersible rigs. These use subsea trees, and workovers require moving a costly rig to the location. Solving problems remotely—with an interventionless method—provides huge savings and fewer risks.

This paper focuses on the first global installation of a gravel pack system that allowed continuous pay zone chemical treatment pumping without interrupting production. For wells with issues such as barium and calcium sulfates causing obstruction at the sand control screen base pipe holes, this system allowed pumping of scale inhibitors (or any other chemical treatment) to the end of the horizontal well (toe) or to other parts of open- or cased-hole sections without needing to stop production.

For this first installation, the system incorporated zonal isolation with feedthrough capabilities using reactive element packer and multiple injection nipples technology, taking advantage of a long shale segment to divide the well in two parts. In general, the number of injection nodes with the same pumping line could vary from well to well. However, at this deepwater installation offshore Brazil, the system was designed to allow continuous pumping of chemicals through only one small-diameter down into a horizontal open hole, to inside the sand control screens at two separate sections of the well, one at the toe and another above the reactive element packer.

The system allowed for screen assembly installation and gravel pack pumping in one trip. A reconnect anchor seal assembly was designed and used to deliver a continuality of the flowline conduit from the gravel pack assembly to the upper string assembly. It also incorporated a cost-effective, high-flow liner system for the conduit/injection mandrel protection and a special feedthrough quick connector to simplify certain steps in the assembly. This allowed for torque and traction transmission in open-hole deployment. This paper will describe the implementation and installation of this new system.
Effect of Emulsifier Concentration and Acid Volume Fraction on the Elastic Properties of Emulsified Acids
Authors: Sayed M. A. , Nasr-El-Din H. A.
Published: September 2011

Acid in diesel emulsified acids have been used in the oilfield for many years. Unlike other acid systems, such as gelled and viscoelastic surfactant-based (VES) acids, where the mobility of hydrogen ion controls the overall rate of the reaction, emulsified acid/rock reaction involves the transport of acid droplets in the diesel phase to the rock surface. Upon contact with rock surface, acid droplets breaks and then the actual reaction on the surface occurs. The emulsified acid has several advantages including the minimum number of acid additives and low corrosion rate. The most important properties of emulsified acid are the viscosity, stability and reactivity. These properties are greatly affected by acid droplet size. Based on our knowledge, the effect of the droplet size on the elastic properties of emulsified acid was not studied before.

The main objective of this paper is to provide a detailed description of the elastic properties of the emulsified acid. In order to perform that, a HPHT rheometer was used. The oscillatory shear measurements were carried out on a series of emulsified acid samples. Different parameters can affect the behavior of the viscoelastic properties of the emulsified acid; such as emulsifier concentration, acid to diesel volume ratio, and acid additives.

The rheological properties depend on the droplet size. At low emulsifier concentration, coarse emulsion, elastic properties were dominant only at high frequency. At high emulsifier concentration, fine emulsions, viscous properties were dominant. Acid additives that affect the droplet size will affect the rheological properties of emulsified acid.
Poseidon Gas Handling Technology: A Case Study of Three ESP Wells in the Congo
Authors: Camilleri L. , Brunet L. , Segui E.
Published: September 2011

In the Republic of Congo, the reservoir pressures in the Likalala and Kombi fields have decreased since production start-up and have dropped below the bubblepoint resulting in secondary gas caps. Consequently, the producing gas/oil ratio (GOR) and gas void fractions (GVFs) of the wells have increased. These fields are produced using electrical submersible pumps (ESPs); however, the drawdown has been limited by traditional ESP gas handling technology, which typically cannot handle GVFs higher than 40%. Total E&P Congo installed three ESPs with advanced helicoaxial pump technology in these two reservoirs. After nearly 2 years of operations on wells Likalala 106 and Kombi 102, production has stabilized and increased as a result of eliminating shutdowns and increasing drawdown. On the third well, Likalala 112, helicoaxial technology ensured that production targets were achieved despite unexpected high GOR and GVFs. This paper reviews these applications, focusing on the ESP and well outflow simulations, which demonstrate that the higher GVF handling capability of the pumps provides the technology needed to increase drawdowns. The paper includes analysis and review of well performance, from inflow through to facilities. It also reviews the in-situ GVF performance of the gas handling device with GVFs measurements as high as 80%. A head correction correlation is also matched to the field results providing users with a method for modeling future ESP applications with high GVF. Finally the downhole gas separator efficiency is reviewed and suggestions made on how future completions can achieve higher separation efficiencies. The results are used to provide a benchmark and design guidelines for future high GOR-ESP applications.
Use of Improved Gridding Technique in Coupled Geomechanics and Compositional Reservoir Flow Simulation
Authors: Shrivastava Vijay , Tran David , Nghiem Long , Kohse Bruce
Published: September 2011

Coupled reservoir flow and geomechanics simulations are important in many compositional fluid flow processes like water-alternating-miscible gas injection and CO2 storage. The intention in these models is to understand the effect of stress and deformation consequent to changes in reservoir flow and fluid phase behavior. Safe CO2 storage in deep saline aquifers calls for evaluation of cap-rock and seal integrity via stress responses so that undesired leakage through the seals could be avoided. In the geomechanics calculations unknowns at a large number of finite element nodes need to be solved at each coupling step, which can lead to overwhelmingly large computation time for the coupled simulations.

Recently an improved gridding technique was applied to model coupled geomechanics and reservoir flow in a thermal simulator. In this technique, a dual grid system consisting of separate grids for the reservoir flow and the geomechanics calculations is used. The exchange of information of the variables between reservoir and geomechanics simulators was accomplished in an iteratively coupled fashion. This method showed significant reduction in CPU time compared to single grid coupled simulation.

This paper presents an extension of the above method wherein the geomechanics model is coupled with an equation-of-state compositional simulator in place of a thermal simulator. Use of the dual grid system is demonstrated through simulation models for two compositional processes. Comparison between a dual grid system and a single grid system is presented. The results show that there is substantial saving in computation time and memory requirement without significant loss in the quality of flow or geomechanical results.

The dual grid system presented in the paper can be used to model compositional processes in stress-sensitive reservoirs to yield satisfactory results in considerably less time than would be possible through a conventional single grid system for coupled flow and deformation simulation.
Rapid Producibility Evaluation of Thin, Sand-shale Laminated Reservoir - A Case Study in South China Sea
Authors: Guo Shusheng , Cai Jun , Li HuiGeng , Xian ChengGang , Song Ju
Published: September 2011

Laminated sand-shale reservoir poses many challenges in formation evaluation and hence risks on decision making such as oil testing or completions, particularly for offshore. This paper presents a new approach of NMR based rock typing, permeability characterization and rapid production prediction for thin sand-shale laminated reservoir, conducted in an offshore field of South China Sea. The method is validated through a study integrating logs, formation tester and drill string test (DST) data, to build a generally applicable approach. It was used for rapid producibility evaluation right after openhole logging, in order to facilitate the decision making of the consequent completion and production test. Based on a quick yet reliable answer, operators can decide whether the well should be completed and where should be tested in order to achieve the lowest cost and HSE impact and better time efficiency for exploration and appraisal.

The major challenges facing are: highly laminated sand/shale sequences, strong heterogeneities, complex porosity-permeability relationships, and different scales of different measurements. We set up an improved method using NMR measurements to evaluate effective properties within a depth frame of thin beds in order to overcome the resolution challenge because the individual lamination thickness is about centimeters or even thinner, which is much below the resolution of logs. Comparing with DST results, the accuracy of predicted producibility is in an acceptable range, giving great confidence of the reliability in the study result. This case study has demonstrated the applicability of the new NMR based method, and set up a rapid producibility evaluation approach for thin, sand-shale laminated reservoir; and this new NMR method and the approach applied are not limited to this specific field but applicable to other fields with similar geological settings and formation types in this region.
Compositional Modeling of Heterogeneous Anisotropic Naturally Fractured Reservoirs using Control Volume Mixed Finite-Element Technique
Authors: Alnahdi O. , Kazemi H.
Published: September 2011

Compositional modeling of heterogeneous anisotropic naturally fractured oil reservoirs is a crucial issue when assessing the benefits of miscible and immiscible gas injection. This is especially true in large Middle East carbonate reservoirs. This paper presents an efficient methodology to model such reservoirs using a control-volume mixed finite-element technique (CVMFE). The formulation takes into account (1) the full permeability tensor without any compromise and (2) the local interaction of gravity, capillary and viscous forces between fracture and matrix.

We give a clear account of the mathematical formulation so that the readers can utilize the method for writing their own computer code. The formulation pertains to a multi-component three-phase flow system using the dual-porosity model where capillary and gravity forces are accounted for, both on the local and global scales. The local scale is related to the fracture-matrix interaction, while the global scale represents the inter-well flow and flow migration across the field. The compositional formulation used (i.e. a volume-balance approach) is based on the fact that pore volume should be equal to the fluid volume in the control volume simulation grid.

CVMFE method is used to discretize the flow equations for the pressure and velocity of each phase simultaneously. The CVMFE method provides a more accurate solution because the continuity of the velocity across the control volume boundaries is honored in spite of the fact that flow potential gradients are discontinuous in the heterogeneous anisotropic scenarios. After obtaining the pressure solution, we use a specific CVFE to calculate the molar compositions.

Finally, a comparison of the mixed finite-element formulation with that of conventional finite-difference schemes is shown. Both methods emphasize the multi-scale issue of interaction of various reservoir forces and reservoir anisotropy which must be accounted for when planning a major gas injection project.
Challenges of Wireline Formation Testing and Fluid Sampling in Tight, Low Permeability Gas Reservoirs: Case Study from Saudi Arabia
Authors: Omokaro Felix Abu , Musharfi Nedhal M. , Soliman Wael , Rourke Marvin , Eid Mahmoud
Published: September 2011

Saudi Aramco's operations cover a wide range of environments, some of which are multilayer gas reservoirs, consisting of thinly-laminated shaly sands. Evaluations based on conventional log data often prove to be inconclusive. Wireline formation testers are routine sources of reservoir pressure and fluid samples that address uncertainties in these formation evaluations.

In general, low permeability reservoirs pose numerous challenges for obtaining successful pressure measurements and fluid samples, including supercharging effects and "tight" tests, where no pressure measurements or samples can be obtained. In some cases, tight reservoir permeability prevents an adequate and competent mud cake buildup, which can prevent sealing of the conventional rubber probe type pads. In this paper, the authors share the different approaches employed under some of these challenging conditions in getting representative pressures and samples. Proper selection of tool configuration and appropriate pad and packer design were key success factors.

In the paper, we highlight how to use pre-job modeling to improve pressure testing and fluid sampling.. In our examples, pre-job modeling were done to predict the expected rates and drawdowns. We used dual ports within the straddle packer testing interval, which permits the segregation of gas and the filtrate. This allowed the formation fluid to be sampled faster than a single-port packer design or probe type tool. We also demonstrate how a combination of pad type probes and dual packer helped to enhance the success rate and reduced our pumping time during sampling.

This paper reviews cases of testing in tight gas reservoirs. It also demonstrates how we improved the success rate of our pressure testing and sampling by combining modern wireline formation testing (WFT) functionalities and effective pre-job planning. This approach is helping us meet the challenge of obtaining representative pressures and fluid samples in low permeability formations.
Achieving Target Solids-Free Gas Rate from Highly Unconsolidated Sandstone Formation Intervals
Authors: Abulhamayel Nahr , Solares J. Ricardo , Nunez Walter , Malik Ataur , Basri Mustafa , McWiliams Andrew , Tahir Oumer , Abduldayem Mohammad
Published: September 2011

One of the most challenging aspects of producing wells drilled in the northernmost section of the unconsolidated pre-Khuff gas bearing reservoirs in Saudi Arabia is to achieve solids-free production while trying to achieve high gas rate targets. A high degree of success in meeting this challenge has been achieved by implementing a fracturing for sand control strategy, whereby proppant fracturing treatments with a tip screenout design and a combination of other techniques have been successfully placed in a number of producers throughout the gas development program. Subsequently, challenging reservoir conditions, including high temperature and pressure, high stress, heterogeneity, and the absence of stress barriers make placing the fracture treatments very difficult, time consuming and expensive. Therefore, in pursuit of optimum, simple, and cost-effective solutions to the challenge of achieving solids-free gas production, Saudi Aramco successfully set stand-alone screens in wells completed open hole in a sandstone reservoir, and achieved excellent results while significantly reducing costs by eliminating the need for a fracturing treatment and streamlining all other operations.

This paper provides details about the geology of the sandstone reservoir, well and screens selection criteria, the screens deployment procedure, post-deployment results, and lessons learned from a two well pilot test. The successful results achieved from the pilot test opened the door for further implementation of the technology and optimization steps.
Recent Advances in Pore Pressure Prediction In Complex Geologic Environments
Authors: Huffman Alan R. , Meyer Jeffrey , Gruenwald Robert , Buitrago Javier , Suarez Jaime , Diaz Carlos , Munoz Jose Maria , Dessay Jack
Published: September 2011

In recent years, methods have been developed to enable robust pressure prediction in the presence of multiple pressure mechanisms including undercompaction, unloading processes (secondary pressure mechanisms) and at great depth, the onset of secondary chemical compaction. These models utilize geological and geophysical information to constrain the calibration models and the depths at which they must be applied to develop a multilayer pressure calibration model that will accurately predict pressures for prospect-level analysis and pre-drill prediction. These models are then integrated with the velocity field and the geological and geophysical information to predict pore pressures and fracture pressures at greater depths than have been previously feasible. This methodology has been tested in multiple basins and has been proven to be effective in helping drilling engineers improve well performance through more effective mud and casing program designs that significantly reduces well costs and rig time.

Recent application of elastic and acoustic inversion in complex carbonate environments have also proven effective in predicting pressures in environments where the shales can be separated from the carbonates. The approach requires that the inverted data be separated into the shale and carbonate velocity trends to allow the shales to be used for effective stress prediction while the complete velocity field is used for time-depth conversion. These studies have revealed that pore pressure prediction from mixed lithology (carbonate and shale) environments is feasible using advanced inversion methods. Successful pressure prediction in this type of geology requires seismic data that is of sufficient quality to enable a robust acoustic and/or elastic inversion to be performed that can separate the shale velocities for effective stress calculation, and perform time-depth conversion from the complete velocity field. As the amount of shale present in the geologic section becomes smaller, the ability to predict pressures decreases. The presence of marls also presents a problem because the carbonate material within the shale suppresses the sensitivity of the shale velocity to pore pressure.
Regional Geological Understanding of Offshore Cyprus and Lebanon from Interpretation of Dual-sensor Streamer Data
Authors: Skiple Cecilie , Sortemos Thore , Lie Øystein , Lowrey Caroline J. , Semb Per Helge
Published: September 2011

Dual-sensor cable seismic data has been acquired over the Eastern Mediterranean area. The data has improved the seismic quality, and this has enhanced the understanding of the subsurface of the region. In this paper, we take this dual-sensor data, merged with conventional seismic data to review the offshore areas of Cyprus and Lebanon in the Eastern Mediterranean. The regional geology of the area has been summarized, and the horizons and intervals most significant for hydrocarbon exploration have been described. A brief introduction to the dual-sensor technology and its benefits are described, but the main focus of the paper is to show how the regional geological understanding has been increased based on the new seismic data. Selected regional profiles over the Levantine and Herodotus Basins with their associated areas including the Eratosthenes Continental Block, the Cyprus Arc and deformation front and the Levant Margin illustrate the principal tectonic features and regional key horizons. In addition, specific seismic lines are presented to illustrate particular depositional features, as a possibly large clastic system in the north-eastern part of the Levantine Basin. Isopach maps are used to describe the thickness variations across the area. Parts of the region may contain all the ingredients for a working petroleum system with the key ingredients of potential source, seal, reservoir and trap in place. In addition it is possible that the size, geological complexity and lack of well-data, mean that the existence of ‘yet to be discovered’ play-types in the area cannot be entirely discounted?
Design, Completion and Optimization of High-Pressure/High Rate Offshore Gas Wells
Authors: Uzcategui E. A. , Ahmari A. S.
Published: September 2011

To meet gas demand, Saudi Aramco is developing three new offshore gas fields with a relatively low number of high rate gas wells. These fields have the particularity of having a very high-pressure and high content of H2S and CO2 in its gas composition.

To develop these fields, a concept of multi-slot platforms with highly deviated wells and 7" monobore completion was initially considered. Later, due to several challenges, a full review of the well construction and completion was carried out for these three fields to be able to minimize risks and achieve the production target.

The new development schemes implemented are considering double annulus seals to avoid communication and to ensure proper formations isolation, relocation of the tubing retrieval subsurface safety valve, operational wells cleanup procedure to ensure production solids free at a higher production rate, and 7" and 958 " monobore completion for production tubing to achieve the production target and minimize requirement.

This paper discusses the new development approach and completions, including the basis for the design.