bluuebunny/crossref_metadata_2025 huggingface dataset:
Petrophysical Evaluation of Shale Gas Reservoir: A case study from Cambay Basin, India
Authors: Tyagi Anil , Abedeen Ainul , Dutta Tanmoy
Published: May 2011

Shale Gas/ Oil exploration is getting more and more attention as the existing fields, are in mature stage of production, therefore, time has come for finding the alternate energy resources. Shale gas is one of the future energy resources Therefore, it is essential to address the problem associated with the potential evaluation of shale gas reservoir.

Most of the shale gas reservoirs are fine grained sand or siltstone. It is not possible to find out true potential of reservoirs with the help of conventional logs / methodology. Before the field is even considered for shale gas evaluation, it is essential to acquire TOC and VRO data of the formation. The best way to acquire this data is conventional core or side wall core. Due to time constrained this data is not always acquired or sufficiently sampled. Therefore evaluation of these parameters, TOC and VRO, using the conventional logs is the only option left. With the help of log data, not only the calibrated values at depths can be generated but it gives a continuous log of these properties. These properties when combined with basin modeling studies than it give full hydrocarbon potential volume.

The current study deals with the Cambay Basin where silty sand reservoir has been identified as hydrocarbon bearing. An attempt has been made to determine shale-gas prospectivity of Cambay shale integrating wireline log, mud log, cutting and core data. The affect of gas present in shale reservoir is visible on logs specially neutron, density, acoustic and resistivity. Mud log data also indicates the presence of possible gas bearing zone in study area based upon gas count.

Using a specific workflow, hydrocarbon saturation, porosity and permeability of the reservoir section was computed. The same parameters were used for OGIP calculation & TOC calculation. Thermal Maturity (VRO) computation was done by using log data by making some assumptions. Log derived thermal maturity was calibrated with side wall core VRO in drilled wells. This transform is then used in other wells where core data is not available and undrilled portion of study area for calculation of thermal maturity. Depositional environment classification and facies analysis was done with the help of log data by using neural network technique. The techniques have demonstrated the methodology for shale gas potential evaluation and can be used for different reservoirs.
Intelligent Field Data Management: Case Study
Authors: Naser N. A. , Awaji M. A.
Published: May 2011

Real time represents the backbone and the outmost critical component of the intelligent field implementation in Saudi Aramco. Over the past few years, several guidelines and standards have been established to govern the real time data flow from fields to users' desktop. These guidelines and standards are defined to meet intelligent field data acquisition and delivery requirements for reservoir and production engineers. Saudi Aramco internally initiated an assessment to study the current real time management practices in order to tap and leverage on the existing guidelines as well as propose possible enhancements that will add value to the intelligent field implementation.

This paper discusses and assesses, through a case study, the intelligent field real time data management steps in the intelligent field data management implementation in Saudi Aramco which includes: Data standardization, Data filtration and compression, Data quality control, Data quality and transmission key performance Indices, Data visualization, and Systems reliability and availability. Also the paper highlights the challenges in intelligent field real time data management to meet intelligent field data acquisition and delivery requirements. Finally, recommendations are proposed to improve real time data management.
A New Approach to Determine Filter Cake Properties of Water-Based Drilling Fluids
Authors: Elkatatny S. M. , Mahmoud M. A. , Nasr-El-Din H. A.
Published: May 2011

Previous studies indicated that the filter cake was heterogeneous and contained two layers with different properties such as thickness, porosity, and permeability. The difference in properties will affect the filtration process and the filter cake buildup for each layer. Previous models of filter cake buildup assumed that the filter cake was homogenous and contained one layer, which undergoes compression followed by buildup.

The objective of this study is to measure the thickness of the two layers of the filter cake and its effect on the filtration process by using a new approach. Our objective also is to develop a valid method to determine local filtration properties, porosity and specific resistance, for each layer in the filter cake. A HPHT filter press was used to perform the filtration process under static conditions (225 °F and 300 psi). CT (computed tomography) scanner was used to measure the thickness and porosity of the filter cake.

The results obtained from the CT scan showed that there was an inflection time at 7.5 min of filtration at which the process changed from the compression to buildup. Compression region before 7.5 min, in which the thickness of the external and internal layer decreased and there is a great change in the average porosity in both layers. Buildup region after 7.5 min, in which the thickness of the internal layer increased from 0.03 to 0.07 in. and the average porosity decreased from 35 to 15%. The thickness of the external layer also increased from 0.04 to 0.09 in. and the average porosity decreased from 25 to almost 0.0% due to poor sorting in this layer, which prevented more filtration thereof. The new approach better explained the change in thickness and porosity of each layer of the filter cake with time.
Sensitivity of Elastic Properties to Fabric Heterogeneity in Carbonate Rocks
Authors: Sharma R , Prasad M , Batzle M , Vega S
Published: May 2011

Carbonate reservoirs hold more than 60% of the world's total remaining oil and 40% of gas reserves (Schlumberger, 2007). With recovery factor averaging around 25–30%, these reservoirs still have substantial amount of trapped hydrocarbons. The primary reason for this poor exploitation of reserves in carbonate stems from the fact that it is challenging to characterize storage and flow properties in these reservoir. Carbonate rocks are known to exhibit depositional and developmental processes (EOR flooding) related heterogeneity. Diagenetic processes like dissolution and precipitation in presence of certain fluid types such as: brine, may have drastic effects on the matrix properties (Eberli, 2003). Diagenesis can trigger heterogeneous distribution of petrophysical properties that may lead to heterogeneous saturation and elastic property distribution. We present our analysis on sensitivity of heterogeneity in carbonate fabric to time-lapse flow and elastic properties variation. We found that at full (end point) saturation, the most heterogeneous sample imbibed 20% less brine than the least heterogeneous sample. Also, at full saturation, the least heterogeneous sample showed 45% more increase in normalized bulk modulus and 10% more decrease in normalized shear modulus than the most heterogeneous sample. Finally comparing our measurements and Gassmann predictions, it seems that these carbonates mainly exhibit patchy saturation.
Evaluating ICD & MLTBS Applications in Carbonate Reservoirs with Sector Models, to Develop a Green Field Off-Shore Abu Dhabi
Authors: Afia Mohamed Sayed , Allouti Abdelkader , Rincon Alexander , Ouezzani Mohamed R. , Belery Paul
Published: May 2011

A green field offshore Abu Dhabi is planned to be developed with slanted-horizontal wells (single and dual drains) and an optimized five spot water injection scheme. Three major carbonate reservoirs (2 Jurassic & 1 Cretaceous) will be targeted. Challenges appear in the field development plan due to the high heterogeneous nature of the carbonate reservoirs and fault /fracture network uncertainty. The main challenges are the early water breakthrough mitigation and well drain accessibility. This will be overcomed by utilizing Inflow Control Devices (ICD) coupled with Sliding Sleeve (SSD) to ensure uniform water front displacement across all reservoir layers and control water breakthrough, and Multi-Lateral Tie Back Systems (MLTBS) to allow Coil Tubing (CT) access to the well upper horizontal drains.

This paper describes the workflow that was used to evaluate the benefits of ICD-SSD & MLTBS using sector models, and presents some results. The sector models cover representative areas of the studied reservoirs.

History match using the available dynamic & static data acquired during field appraisal was conducted to calibrate the sector models. The data included well test data (Flowing & Build-up tests), zonal contribution from production logging, and MDT reservoir pressures, where available. Faults / fracture network uncertainty was addressed using "what-if" scenarios.

The study confirmed the potential significant increase in oil recovery by using ICD equipped with SSD. MLTBS providing CT accessibility to the upper drain of the dual lateral wells was shown to positively impact well productivity and oil recovery.
Impact of Wettability Alteration on Recovery Factor
Authors: Aziz Abdulla Karimov
Published: May 2011

Recovery Factor is one of the key elements in determining commercial viability of hydrocarbon fields. It has been recognized that the recovery factor, apart from other parameters, depends on wettability of the reservoir rocks which in turn affects calculations of other parameters used in the volumetric equation. This study is concerned with the impact of wettability alteration due to production on resistivity saturation exponent used in the Archie equation and its subsequent effect on reserves calculations.

The idea is to compare capillary pressure derived saturations measured from laboratory tests on water wet samples and those derived from total porosity resistivity model with cementation and saturation exponents also measured under the same laboratory conditions. The discrepancy between the two is then used as part of the methodology for identification of potential wettability alteration. If discrepancy between the two methods isn’t caused by anomalously high permeabilities or wrong Free Water Level estimations, then by the way of iteration, saturation exponent can be varied until the match between the resistivity model and height function saturations is achieved. The workflow for integration of all saturation estimation sources is developed to back propagate the errors in hydrocarbon volume calculations.
Factors Affecting Production Behavior in Tight Gas Reservoirs
Authors: Khan Waqar Ali , Rehman Shah Abdur , Akram Agha Hasan , Ahmad Ammar
Published: May 2011

Abstract

Tight Gas Reservoirs (TGR) are one of the primary types of unconventional reservoirs to be exploited in the search for longlasting resources.TGR's are difficult to produce for a number of reasons. Due to their low productivity a thorough understanding is needed regarding the factors that affect gas production rate over the life of these reservoirs.

This paper is focused on analyzing the effects of drainage area, gas rate, fracture conductivity, porosity, and reservoir permeability on production performance. In particular, the impact of permeability, from ultra tight (0.0004 md) to tight (0.1 md) reservoirs, on drainage area and reserves is analyzed in detail.

A semi-analytical simulator is used in this study. A conceptual case study was performed comparing a hydraulically fractured vertical well with a multiple-fracture horizontal well in same reservoir. Fracture conductivity is estimated by using StimLAB proppant consortium correlations for different flow rates, which takes into account non-Darcy pressure drops and other factors.

The results of this work conclude that in ultra tight reservoirs, the drainage area is significantly reduced. Only the near fracture rock is drained, and a high density of wells and fractures is needed. This behavior changes with increase in reservoir permeability. In ultra-tight reservoirs, horizontal wells with multiple fracs may be the only viable option for commercial production. A general workflow is also described as to how forecasting in such reservoirs can be made more accurate.

Introduction

With the increasing demand for oil and gas, and declining production from existing fields, conventional hydrocarbons cannot meet the current and future energy demands of the world. The oil and gas industry is investing in the development of methods and technologies needed to exploit unconventional resources. Fig-1 shows the resource triangle (Holditch 2006; Hein 2009) and describes how unconventional reservoirs are different from conventional reservoirs in regards to technology required for commercial exploitation and reservoir volumes. Compared to conventional reservoirs, unconventional reservoirs are larger in volume but difficult to exploit. In the resource triangle as we move towards unconventional resources, better technology in drilling and development are key factors to success. Unconventional resources include tight gas reservoirs, gas hydrates, Coal bed methane, and oil shales.

This paper is focused on tight gas reservoirs (TGR). The term Tight Gas is commonly used for referring to low permeability reservoirs producing dry natural gas (Holditch 2006). Though the definition of Tight Gas Reservoirs is different in different parts of the world, there is general agreement that permeability below 0.1 mD characterizes tight gas reservoir. In some countries, for purposes of gas sale pricing, TGR can have permeability upto 1 and even 2 md. In this paper we look at permeabilities below 0.1 mD.
A Holistic Approach to Detect and Characterize Fractures in a Mature Middle Eastern Oil Field
Authors: Alhuthali Ahmed H. , Lyngra Stig , Widjaja Danang R. , Al-Otaibi Uthman F. , Godail Loic
Published: May 2011

Naturally fractured reservoirs are recognized as challenging reservoirs to manage. The appropriate balance between production at acceptable oil rate and attaining high ultimate oil recovery is often difficult to find in these reservoirs. A good understanding of the fracture systems is essential for a successful development since the fractures significantly impact reservoir fluid flow and well productivity. Additionally, accurate fracture description in reservoir models is critical for reliable production forecasts.

The main objective of this paper is to demonstrate a holistic approach to detect and characterize fractures in a mature oil field in the Middle East. The study was conducted by analyzing the dynamic data, such as production, reservoir pressure, pressure transient analysis (PTA), production logs, water salinity, drilling mud losses and image logs. The study results included evidence of fracture impact on field behavior, inter-reservoir communication and fracture properties quantification leading to recommendations for future reservoir management strategy and further development.

The evidence of fracture impact on field behavior was evaluated through extensive analysis of well performance of more than 300 wells. The field consists of two reservoirs separated by a thick nonpermeable zone. The Upper reservoir is prolific, while the Lower reservoir is relatively tight and highly fractured. The communication between the two reservoirs was investigated by comparing Lower reservoir wells with the neighboring wells in the Upper reservoir. All available data were taken into account, including the production gas-oil ratio (GOR), reservoir pressure, and water cut profile and produced water salinity, as well as water breakthrough time. A material balance approach was utilized to confirm and quantify the communication between the two reservoirs. Data integration enabled deriving a series of probable links between the two reservoirs used for constructing representative fractures maps. Fracture conductivity was quantified using both pressure transient interpretation and production log results.

The reservoir management team has utilized the study outcome to re-engineer the well architecture in both reservoirs. Additionally, active measures are taken to improve oil recovery from both reservoirs.
Field Application of a Modified Kozeny-Carmen Correlation to Characterize Hydraulic Flow Units
Authors: Nooruddin Hasan , Hossain M. Enamul , Sudirman Sharizan Bin , Sulaimani Thamer
Published: May 2011

Hydraulic Flow Unit (HU) has been used extensively as a technique in permeability modeling and rock typing. Amaefule et al. (1993) introduced for the first time the concept of Reservoir Quality Index (RQI) and Flow Zone Indicator (FZI) by using the Kozeny-Carmen (K-C) model to characterize HU and predict permeability in uncored wells and intervals.

This technique has helped in enhancing the capability to capture the various reservoir flow behavior based on its respective characters. Yet, there are challenges in using the original correlation due to its inherent limitations and over simplified assumptions that prevent accurate HU definitions. This study highlights some of those shortcomings and proposes a modified K-C correlation that enhances the HU characterization.

It is found that the conventional K-C model ignores the inherent nonlinear behavior between the tortuosity and porosity. Hence, handling the tortuosity term in a more representative manner demonstrates a more rigorous correlation that extends the applicability of this powerful technique into more heterogeneous rocks – such as those found in carbonate reservoirs.

This paper presents a reservoir simulation case study that is conducted to validate the applicability of the proposed model as a rock typing technique in a heterogeneous carbonate reservoir in the Middle East region. Relative permeability curves, Leverett J-Function curves and initial water saturation distribution show good agreement within each HU generated using the proposed model.

It is recognized that modified Kozeny-Carmen technique give better matching of initial water saturation model than the conventional technique when compared to open-hole logs which, in turn; adds confidence to initial hydrocarbon-in-place calculations and reservoir behavior predictions. This result will ultimately enhance the prediction of reservoir performance under various scenarios in reservoir simulation.
Tight Gas Petrophysical Challenges in Saudi Aramco
Authors: Forsyth David , Al Musharfi Nedhal Mohammed , Al Marzooq Anas M.
Published: May 2011

Recently, Saudi Aramco upstream activities in unconventional gas, and in particular tight gas sands, have been identified as a focus area. Integral to understanding the potential of tight gas as a resource, is an understanding of the petrophysical characterization of tight gas intervals. This paper presents a review of the petrophysical challenges in the evaluation of tight gas intervals encountered within an existing producing field producing from formation U. This formation can be highly variable and although it can be highly productive, in some areas the geology has produced poorer reservoir quality rock. Production from wells which penetrate these areas can exhibit "Tight Gas" characteristics. Core and log data from existing fields are abundant and cover both good and poorer quality reservoir intervals. The factors which impact the evaluation of these "Tight Gas" intervals, in this relatively well sampled environment, can be generalized to the evaluation of less well studied tight gas formations. The results of this review identify many areas where current techniques and tools fall short of providing an adequate characterization. In particular, the quantification of mineralogy and diagenesis is seen as important, as is the quantification of saturations and accurate measurement of micro-Darcy permeabilities. Areas where current techniques require improvement are highlighted and projects that are in progress to address these issues and improve the evaluation of tight gas are detailed. One area which is highlighted as holding potential is rock typing, which can categorize different types of tight gas interval based on clay content or mineralogy. Three wells have been selected for a fracturing exercise as a proof of concept to assess the production potential. The results of the fracturing exercise are presented relative to the petrophysical evaluation of these wells.
Formation Damage Concern from Water-Base Mud Filtrate in Deep Gas Wells: Case Study
Authors: Ekpe Joseph , Kompantsev Andrey , Khakimov Ayrat , Mohammad Emad , Ganizade Fazil , Madkour Ali , Ashoor Ayman , Al-Ali Ali , Al-Khalifah Fadhel
Published: May 2011

Lukoil Saudi Arabia Energy Limited(LUKSAR) started a Deep ‘Tight Gas’ exploration campaign in the Rub Al-Khali Empty Quarter in 2006 and nine wildcat exploration wells have been drilled and evaluated with one Appraisal well in its Field Fig. 1. These prospective deep gas discoveries in the Empty Quarter have occurred in relatively High Pressure/ High Temperature (HP/HT) horizons at depths between 15,000 and 20,000 feet, where the stress and temperature are extremely high in addition to low reservoir permeability. This has made the exploration activity more challenging.

Well test and clean up results from different completion strategy has not yield convincing results due to many factors. Some of these include: well placement, fluid selection, completions and frac designs. Nonetheless, the starting point in evaluating the success of well operations in the life cycle of a well remains selection of suitable drilling fluid of which its solids and filtrate particles are very friendly to the given reservoir (i.e minimum damage effect). Although the drainage radius of these wells may be several hundreds of feet, the effective permeability close to the wellbore may have a disproportionate effect on the well productivity.

This paper summarizes the challenges encountered in the use of water-base mud (WBM) and the subsequent mud filtrate effect on the reservoir permeability through different test analysis on core samples and logs interpretations. But most importantly the result raises the need for continual research and development in the area of formation damage prevention and avoidance in deep gas drilling of ultra-low permeability reservoirs.
Log-Based Rock Property Evaluation – A New Capability in A Specialized Log Data Management Platform
Authors: Odunlami Tosin , Soroush Hamed , Kalathingal Paul , Somerville Jim
Published: May 2011

Oil and gas companies are increasingly seeking production from more challenging reservoirs associated with costly geomechanical problems. Knowledge of in-situ rock strength is a fundamental element of geomechanical analysis for the oil and gas industry in estimating such elements as wellbore stability, solids production, hydraulic fracturing, bit selection, cap rock integrity, compaction, and subsidence studies. Specifically, this information is critical for successful drilling of directional, highly deviated, and horizontal wells. In production phase, this provides information to maximize the efficiency of wellbore perforations and hydraulic fracturing, and also assess the requirement for sand control equipment.

Log-based rock strength modeling is a technique which enables estimation of in-situ mechanical rock properties from some petrophysical logs. This technique is currently the most popular approach in order to evaluate mechanical rock properties, as laboratory tests are costly and time consuming. The important rock properties which are desired to be determined include; Uniaxial Compressive Strength (UCS), friction angle and cohesion in addition to rock elastic constants (Young's modulus, Poisson's ratio, bulk modulus and shear modulus). This technique has a number of advantages over laboratory measurements of geomechanical properties including (but not limited to): availability of log data, providing continuous property profiles, possibility of modeling weak intervals, low cost, and time effectiveness.

In this study, a comprehensive review of currently available empirical equations developed by different authors is provided. In addition, algorithms for all the equations are developed and subsequently coded into a specialized log data management platform designed for petrophysical and Image log Analysis, thus converting it into a powerful tool for rock property estimation for a variety of rock types and specifications.
Coiled Tubing Sand Clean Outs Utilizing BHA Technology and Simulation Software in Demanding Wellbore Geometries
Authors: Li J. , Green T.
Published: May 2011

Although efforts are made to reduce or eliminate sand production in a producing well, sometimes sand fill is an unavoidable by-product of well conditions and the need for a cleanout intervention is necessary. Various cleanout methods have been utilized in the past, including the use of coiled tubing. Removing sand fill from a well using coiled tubing is one of the earliest applications for CT and continues to be an important service to the industry today.

Historically, coiled tubing cleanouts have incorporated high circulation rates, exotic/costly fluids and reverse circulation to remove solids. Many of these conventional sand cleanout methods often apply excess hydrostatic pressure on the formation, resulting in lost circulation in low formation pressure reservoirs. Incorporating large liner geometries with smaller completion restrictions magnifies the task at hand as the annular velocities are drastically reduced even with higher coiled tubing circulation rates.

Using a specially developed cleanout tool and a computer simulator for solids transport provides an opportunity to optimize the operation for the removal of solids to near 100% efficiency, with all fluidized solids being removed. Simplified operational procedures allow for making a more qualitative decision about the cleanout efficiency.

This paper will show cost effective solutions utilized in Saudi Arabia from 2007 to present by providing an overview of all field cases and job optimization. The main focus of the paper will be to highlight and compare the coiled tubing cleanout job design process, operational procedures, results, and lessons learned from two case studies; the first case study being a successful cleanout, while in the second case study the cleanout objective was not achieved.
Cyclic Pressure Pumping (CPP): A Potential Recovery Method for Fractured Carbonate Reservoirs
Authors: Ikwumonu A. , Rawnsley K. , Bettembourg S.
Published: May 2011

The large permeability contrast between fractures and matrix in highly fractured carbonate reservoirs has been a hindrance to the efficient recovery of the oil from the matrix. Gas oil gravity drainage (GOGD) has been the most appealing option to date. However it is a slow process. Cyclic Pressure Pumping (CPP) is proposed which has the potential of increasing the rate of recovery over GOGD under certain conditions. CPP utilises the fact that due to the much lower permeability in the matrix, the matrix pressure lags behind the fracture pressure during a rapid pressure change. A sudden drop in pressure in the fractures results in expansion of fluids in the adjoining matrix which are discharged into the fracture system. The fluids in the fracture system can then be produced. The reservoir can be re-pressurised by gas injection and depressurised by producing the fluids in an alternate manner.

This process originally called batch gas cycling was suggested in the 50s for improving recovery in non-homogeneous reservoirs over conventional gas flooding. It was tried successfully in a small field in the late 50s. Laboratory experiments in the 70s on low-permeability matrix in contact with high-permeability fractures indicated the effectiveness of the process.

The process was re-discovered during reservoir production optimisation simulation studies in a heavy oil steam injection project in Oman and will be applied to minimise oil loss during steam plant shut downs. Early field observations support the process. The paper presents a study of the process using both dual permeability and single porosity simulation modeling. It also highlights the conditions which are favorable to the process as well as certain practical problems that could be encountered in implementing it.
Error Quantification of Dielectric Spectroscopy on Carbonate Core Plugs
Authors: Zhang Tianhua , Ligneul Patrice , Al-Ofi Salah , Nicot Benjamin , Pairoys Fabrice , Akbar Mahmood
Published: May 2011

The recent introduction of a downhole logging device to estimate rock multi-frequency complex permittivity has motivated the development of corresponding laboratory measurements. Various devices for permittivity measurement are described in the literature. Those instruments generally handle powder samples, millimeter-range thin discs or centimeter-range cylindrical plugs. In carbonate rocks, heterogeneity can be observed from micronic to kilometer scales. Laboratory measurements at similar resolution of the downhole tool can provide useful and justifiable input for the interpretation of the logged data.

A dielectric device which can measure 1.5 in. diameter and 2.0 in. long core plugs with a large coaxial probe is presented in this paper. The repeatability of the measurements are shown to be within 2% of the material dielectric constant value of dry rock plugs and 3% of wet rock plugs normalized with porosity and salinity. The range of confidence for the inferred cementation factor from dielectric measurements is also quantified and the results show that this cementation factor is not sensitive to the brine salinity. Error bars are displayed over dielectric dispersion curves and used as quality control.

Various materials have been tested with this large probe. The measurements on fused quartz, Teflon and ceramic materials match the available published results. Data acquired on pure calcite, dolomite and anhydrite crystals provide a good estimation of the limits of the dielectric properties range for calcium carbonate rocks of complex lithology. In the literature, the properties of these minerals vary over a broad range, which limits their practical use for reservoir characterization.

The design of the probe allows averaging the horizontal heterogeneity of the plug, but by flipping the plug upside down the identification of vertical heterogeneity can be put forward. The heterogeneity can be caused by numerous factors such as lithology, pore system, and fluid saturation variations. The case study presented in this paper shows an example of porosity heterogeneity identified by the dielectric spectroscopy measurements, and confirmed by NMR 1D porosity profiling and CT-scan imaging.
Triple-porosity Models: One Further Step Towards Capturing Fractured Reservoirs Heterogeneity
Authors: Al-Ahmadi Hasan A. , Wattenbarger R. A.
Published: May 2011

Fractured reservoirs present a challenge in terms of characterization and modeling. Due to the fact that they consist of two coexisting and interacting media: matrix and fractures, not only we need to characterize the intrinsic properties of each medium but also accurately model how they interact. Dual-porosity models have been the norm in modeling fractures reservoirs. However, these models assume uniform matrix and fractures properties all over that medium. One further step into capturing the reservoir heterogeneity is to subdivide each medium and assign each one different property. In this paper, fractures are considered to have different properties and hence the triple-porosity model is introduced.

The triple-porosity model presented in this paper consists of three contiguous porous media: a matrix, less permeable microfractures and more permeable macrofractures. These media coexist and interact differently in the reservoir. It is assumed that flow is sequential following the direction of increased permeability and only macrofractures provide the conduit for fluids flow. Different solutions were derived based on different assumptions governing the flow between the fractures and matrix systems; i.e., pseudosteady state or transient flow in addition to different flow geometry; i.e., linear and radial. Some of these solutions are original. The model was confirmed mathematically by reducing it to dual-porosity system and numerically with reservoir simulation and applied to field cases. In addition, the solutions were modified to account for gas flow due to changing gas properties and gas adsorption in fractured unconventional reservoirs.
Application of Advanced Volume Interpretation (AVI) Workflows to Improve Data Quality for Rapid Interpretation
Authors: Badar Muhammad Haseeb
Published: May 2011

This paper discusses the complete interactive 3D seismic volume interpretation workflow, including choices for 3D attributes, and describes a methodology to extract the maximum information from seismic in an integrated visualization and interpretation environment.

Structural and stratigraphic attributes can help analyze the impact of surface features, like sand dunes and sabkha, on near surface and deeper seismic events. Simultaneous 3D visualization of multiple attributes makes this analysis even easier. Understanding the full effect of the surface geology on deeper events helps reduce errors during prospect generation and well proposal. It is very helpful for the seismic data processor to apply accurate static correction and to take this into consideration during seismic data reprocessing and amplitude normalization.

The proposed Advanced Volume Interpretation (AVI) workflows’ interactive, iterative analysis and filtering techniques improved data clarity for better structural and stratigraphic interpretation.
The Application of Real Time Downhole Drilling Dynamic Signatures as a Possible Early Indicator of Lithology Changes
Authors: Al-Shuker Nawaf , Kirby Cliff , Brinsdon Mark
Published: May 2011

While geosteering wells through hydrocarbon producing formations, early and decisive decision making during the real time (RT) drilling process is fundamentally key to whether the particular well is going to be a good producer, or an exceptional hydrocarbon producer.

Typically, within today's modern Logging While Drilling (LWD) tool suites the bulk density and porosity tools are offset behind the drill bit by the motor, Rotary Steering Systems (RSS) and other bottom hole assembly(BHA) components. Offsets will by their nature incur some data time lag period, determined by the ensuing Rate of Penetration (ROP).

By using RT downhole drilling dynamics the decision process tree can be enhanced and quickened. Changes in drilling system dynamics driven by the bit's interaction with the formation, will be a near instantaneous indicator of changes in formation characteristics and properties. The key being this dynamic data is coming directly from bit depth.

These early RT drilling dynamic changes could be used in collaboration with the existing modern Reservoir Navigation Steering (RNS) techniques, to provide earlier decision making.

In this paper the authors will present, discuss and aim to demonstrate and fully explore the relationship and potential usefulness between the RT drilling dynamic signatures and formation bulk density or porosity changes.
Pioneer Application of a Hydraulic Line Wet Mate Connect System in Combination with a Pod ESP in a Dual Lateral Intelligent Completion Well
Authors: Al-Mohanna Khalid , Kilany Khaled , Rooks Mark K. , Iskandar Riza , Shafiq Muhammad
Published: May 2011

This paper describes a case history detailing design, planning, completions, testing and production of the first worldwide Hydraulic Line Wet Mate (HLWM) connect system. The system was installed in combination with a pod type electrical submersible pump (ESP) in an intelligent completion (IC) dual lateral well in an offshore field in Saudi Arabia. In this field, most of the existing wells are horizontal oil producers drilled inside a high Darcy sandstone reservoir. Inflow control devices (ICDs) are run inside the open hole in both the motherbore and the upper lateral as a part of the lower completion. The upper completion includes IC inflow control valves (ICVs) installed in combination with an ESP. The engineering challenges facing such completions stem from the requirement for hydraulic control lines that are required by the IC for operation and how these control lines are installed as they need to pass the downhole ESP. While the hydraulic control lines could be considered permanent, the ESPs are not as they require periodic replacement whenever they fail. Therefore, the challenge of pulling the ESP system because of ESP failures while maintaining the integrity of the hydraulic control lines used for operating the lower IC is paramount. The HLWM connect system provides the solution to the challenges faced when integrating ESP operations with IC (ICVs, multi-port packers, etc.). It provides the flexibility to replace the ESP without having to retrieve the IC, which saves both cost and time.

The HLWM connect system provides connections for hydraulic control lines in a two-stage intelligent well completion and allows combination of IC with an ESP. It can operate in highly deviated wells and allows multiple connect/disconnect cycles during tubing space-out.

The appraisal and acceptance loop of the completion has been closed by having these wells completed, put on production and tested. Approval of technology was achieved and the anticipated benefits are realized by actual performance of the flow control valves (FCVs) in the IC downhole through the HLWM connect system.

Leveraged knowledge from this pioneer installation has provided an insight into HLWM capabilities and implementation. Moreover, it has set the stage for other field's application of this technology within Saudi Aramco.
Selecting Optimum Completion Strategy – Examples from Saudi Arabia's Unconsolidated Unayzah Reservoir
Authors: Al-Anazi Hasan D. , Al-Qahtani Adel A. , Rahim Zillur , Masrahy Mohammed , Al-Malki Bandar H. , Al-Kanaan Adnan A.
Published: May 2011

The Unayzah reservoir in SA-1 field is highly unconsolidated with heterogeneous sequence of Early Permian sandstones saturated with condensate rich gas. Reservoir characterization based on the seismic, geological, and petrophysical analysis has indicated many stratigraphic units within the main Unayzah-A interval, which consists of well developed Eolian sandstones represented by Eolian dunes, sandsheets and closely associated inter-dune and lake deposits. Due to the unconsolidated nature of reservoir rock, conventional drilling and completion pose a very high risk of producing formation sand along with gas production, which can cause immense damage to production string, wellhead, surface flow lines, and gas plant equipment. In the early development stage of SA-1, frac-pack (F&P) was used and had been successful for several years. The method consisted of creating a short fracture, packing it up with proppant, and placing a screen as part of the completion system across the reservoir section. After years of producing from wells completed with this F&P completion, the scale due to fines migration buildups in the proppant within the annulus and causes high positive skin and deterioration of the screen, and consequently, needs a complete workover to regain lost potential. The workover for a F&P well is nothing less than drilling a new sidetrack as the completion cannot be de-completed and pulled out.

After detailed study and modeling, it was decided to change this strategy and complete the wells with an expandable sand screen (ESS). The completions using the ESS were effective and successful in terms of trouble-free deployment of the equipment and sustained a long-term sand-free rate.

The conventional sand screen (CSS) assembly has also been used in this reservoir. The initial test of this equipment conducted in one of the high producers was successful; however, long-term sand-free production as well as maintaining screen integrity cannot be ascertained. Among the disadvantages of CSS completion is the possibility of wellbore collapse on the screens with the depletion of reservoir pressure (changing near-wellbore stress environment) during production life of the well. In such case, the screen can incur partial or total damage and can no longer resist sand production.

The paper describes in detail the reservoir characteristics and presents numerous examples of different completion methods implemented in the field to prevent sand and ensure high, sustainable flow rate. Long-term performance data are analyzed and presented in this paper to show the performance of sand screen technology.
Safe Execution of Sour Well Tests in the Kidan Field
Authors: Bellerby Philip , Hoekstra Taco , Elias Peter , Wevers Adrian
Published: May 2011

Executive Summary

The South Rub Al-Khali Company Limited (SRAK) is an incorporated Joint Venture between Shell Saudi Ventures Limited (50% share) and Saudi Arabian Oil Company (50% share) to explore for non-associated gas and associated liquids in the South Rub’Al-Khali Basin (Empty Quarter) in the Kingdom of Saudi Arabia.

This paper describes the key HSE processes which were an integral part of the SRAK management system employed to achieve the safe execution of critical sour gas well tests.

SRAK has to date drilled two extremely sour, multiple reservoir wells. During the drilling phase, the H2S gas is kept – by design – down hole in order to minimize any exposure to personnel. However, during the production test phase the production of gas from these sour wells carries one of the highest risk factors in the oil industry. It requires meticulous planning and execution with strict adherence to established plans and procedures. Extensive training and competence assurance is required before allowing highly toxic gasses to flow to surface. These well tests have put the Kidan field onto the map as a potential commercial development, in spite of the high cost of remote desert area operations combined with the inherent complexity of the sour gas contained in the Kidan structures.

This paper will describe the numerous safety challenges involved in the testing of two highly sour wells, SRAK-A and SRAK-B. It also outlines the approach that was followed to ensure safety in design, execution and emergency response planning. Case histories will explain the effective handling of unplanned H2S gas release events on surface will be used to demonstrate the effectiveness of training and systems in place. Learning, and associated introduced improvements, will be described as part of an operational efficiency review.
Underbalanced Drilling (UBD) as a Tool to Test Tight Gas Plays – An Example from the Empty Quarter, Saudi Arabia: Drilling and Reservoir Characterisation Lessons
Authors: Al-Maashari Yousuf , Briner Andreas , Axon Andrew , Wevers Adrian
Published: May 2011

Executive Summary

The South Rub Al-Khali Company Limited (SRAK) is an incorporated Joint Venture formed by Shell Saudi Ventures Limited (50% share) and Saudi Arabian Oil Company (50% share) to explore for non-associated gas and associated liquids in the South Rub’Al-Khali Basin (Empty Quarter) in the Kingdom of Saudi Arabia.

This paper discusses specific data acquisition strategies that have been developed to address the challenges of deep wells in tight reservoirs in remote and harsh environments. While drilling the first three wells SRAK has gone through a very steep learning curve with respect to well data acquisition and integration. It also allowed optimising the data acquisition strategy for future wells that SRAK was planning to drill.

As a direct result of this initial work, and the experience gained by other wells drilled in the Rub’ Al-Khali, SRAK realised that the traditional approach and formation evaluation using static well data gathering was not entirely satisfactory. Industry experience also showed that tight gas exploration and appraisal wells historically involved lengthy multi-year multi-well programs due to inconclusive results from static logging, coring and well testing operations.

In line with Shell's global initiative to use underbalanced drilling (UBD) for tight gas exploration and appraisal, UBD was implemented in SRAK's fifth exploration well in the Rub’Al-Khali. The deeper Palaeozoic reservoirs in the Rub’Al-Khali are known to be commonly tight and susceptible to near-wellbore formation impairment during conventional overbalanced drilling. UBD offered a possible solution for better quality reservoir evaluation and demonstrating any un-impaired potential flow. In other prospects, previous conventional drilling, stimulation and well clean-up had typically failed to unambiguously characterise pay and produce hydrocarbons to surface.

UBD drilling operations were designed and implemented with the support and expertise of the shareholders. Both internal and external subject matter experts supported operations. Whilst numerous UBD specific drilling related aspects were understood pre-drill, significant uncertainty remained around data acquisition and interpretation during UBD drilling operations.

The SRAK UBD project was safe and successfully executed as per the drilling program. Due to the UBD operations there was no ambiguity on presence and mobility of hydrocarbons, thereby avoiding SRAK the completion, fraccing and testing cost which are far higher than the UBD expenditure.

The well SRAK-F offered firsthand experience to the SRAK team to assess the advantage and disadvantage of UBD operations on reservoir characterisation. This paper aims to capture SRAK's learning in UBD drilling and reservoir characterisation.
Horizontal Wells Drilling Activity in South Texas Unconventional Gas Resources and Microseismic Hydraulic Fracturing Monitoring Application to Reduce Risk and Increases the Success Rate
Authors: Sani Abu M. , Ejefodomi Efe A.
Published: May 2011

Unconventional gas resource plays continue to have a significant impact on natural gas production in the US due to recent technological advances and higher demand for gas. In the US, 22% of the total energy consumed comes from natural gas. The US domestic production of natural gas is around 85% of the demand; currently about half of that comes from unconventional resources. Primary unconventional sources are tight gas, shale gas, and coalbed methane (CBM). Tight gas, shale gas and CBM production accounts for approximately 28%, 14% and 8%, respectively, of total US gas production. Total US production for 2010 is 21.57 tcf. Achieving sustainable production from unconventional gas resources requires reaching extended areas of the reservoir and performing effective hydraulic fracturing, with its associated technologies, to help reduce risk and increase the success rate.

Compared to production in vertical wells, the production of tight gas and shale gas in horizontal wells has increased significantly due to the ability to reach extended areas as a result of enhanced drilling technologies. Horizontal wells represent a large portion of the well count in US plays, with rigs for horizontal wells increasing from 10% to 58% of the total drilling rigs within the last 6 years (2005–2010). This increase in activity was achieved through careful engineering designs and use of new technologies to address the complexities involved in planning, drilling, completing, and stimulating horizontal wells. In recent years, microseismic hydraulic fracture monitoring (HFM) has become a key technology in understanding the propagation mechanism of the created fractures during stimulation treatments.

The paper discusses horizontal well drilling activity in a south Texas play over a 6-year period beginning in 2005. Drilling activity trends and completion practices in some tight gas and shale gas formations in the south Texas basin are highlighted. Additionally, the paper takes a look at the application of microseismic HFM to increase the success rate of horizontal wells in the south Texas basin by reducing some of the completion risks and challenges. Finally, the paper discusses ways to improve the overall completion and stimulation designs of horizontal wells in unconventional gas formations to ensure efficient recovery.