bluuebunny/crossref_metadata_2025_split huggingface dataset:
Extending the Life of a Mature Oil Field by Applying Innovative Squeeze Cementing Solutions
Authors: Neto N. Bianchi , Salehpour A. , Hadiaman F. , Biyanni H. M. , Jamal M. N. , Setyawan H. 
Published: May 2011

Abstract
After decades of field and laboratory studies, when compared to primary cementing, squeeze cementing defies standardization as a general practice. Each candidate for remedial cementing presents a unique challenge to the engineer, therefore, to address the variety of problems that may occur, a wide range of techniques has been developed combining placement methods, specific slurry formulations, and execution procedures.
Recent advancement in workover techniques in brown fields which requires well intervention without pulling out or replacing the existing completion mostly for economic reasons, have added extra complications to the remedial cementing operations that makes the job success more challenging. It is a multidisciplinary field requiring knowledge and skills in geo-mechanics, fluid mechanics, and of course, cement-slurry systems.
Handil field is a giant mature oil field in Indonesia that has been producing since 1975 with the current recovery factor of 49% for oil and 57% for gas. Cumulatively, the total oil produced is around 855 MMstb and gas around 1.68 Tcf with the current production of oil at 20,000 bopd, gas at 75 mmscfd and water at 130,000 bwpd. Applying enhanced oil recovery techniques, infill well drilling and light workover operations performed on existing wells are key elements to maintain field production.
This paper outlines the field study analysis with the focus of improving the squeeze cementing success rate from the previous campaigns and will cover innovative solutions specially a novel placement technique that was adopted on a recent campaign. Successful results helped the operator to extend the life of the mature field by maintaining the production at its best level. Also a case history will be covered for the aim of better understanding the challenges being faced for properly isolating the compartmentalized sand reservoirs with different characteristics where proper analysis and innovative approach helped the operator achieving the objectives.
Accurate Prediction of Pressure Drop in Two-Phase Vertical Flow Systems using Artificial Intelligence
Authors: Al-Shammari Ahmed 
Published: May 2011

Abstract
One of the significant parameters affecting flow rate in oil production wells is the pressure drop between the well bottom-hole and tubing head. The pressure drop calculation in two-phase flow systems is very complicated due to the variations in gas and liquid flow rates across the two-phase flow stream. As the pressure of crude decreases while climbing a well tubular, more gas comes out of solution. This gradual increase in gas volumes leads to the reduction of liquid slip velocity and creating new flow patterns that are not only different in shape, but also complicated in pressure drop calculations. To overcome this difficulty in calculating pressure drop in two-phase flow systems, scientists came up with two main approaches: flow correlations and mechanistic models. These two approaches are applicable within certain conditions and their accuracy in pressure drop prediction degrades outside their design boundary ranges.
The raising popularity of Artificial Intelligence (AI) techniques during the past two decades proved that AI can be an alternative solution to many of the complicated problems where physics and classic statistics fail to provide satisfactory solutions. These techniques applied in different upstream fields have provided fast, robust and reliable numerical models in a variety of areas, e.g., geological modeling, reservoir engineering, petrophysics and well testing. This paper describes the utilization of Fuzzy Logic, which is one of the famous AI techniques, in predicting flowing bottom-hole pressure in oil producer wells. Real well testing data from the Middle East were used in constructing the Fuzzy Logic model. After training the model using 596 well testing data samples, it was successfully able to predict the flowing bottom-hole pressure at 199 well testing samples with an average absolute error of 4.9%. A comparison analysis was conducted to evaluate multiple flow correlation in predicting flowing bottom-hole pressure and compare their results with the developed Adaptive Neuro-Fuzzy Inference System (ANFIS) model.
Fracture Imaging Using Azimuthal Prestack Depth Migration
Authors: Sliz Krzysztof (Kris) 
Published: May 2011

Abstract
A major uncertainty in fracture analysis based on the azimuthally variant seismic velocities is the interference from structural effects. Structural dip induces azimuthal variation in velocity, which can mask the influence on travel–times caused by the presence of fractures. In situations where the subsurface geology is complex, Prestack Depth Migration (PreSDM) should be used to correct for the dip prior to the azimuthal velocity analysis. PreSDM is sensitive to velocity variation, thereby making it a good tool for detection of subtle velocity changes. This paper focuses on a fracture detection methodology using a 3D azimuthal depth imaging workflow. The workflow presented here utilizes scanning of azimuthally dependent residual moveout volumes for three-dimensional (3D) mapping of zones with a higher probability of fractures. This analysis can also be used to help determine the fracture style (single or multiple set of fractures). The workflow was successfully applied to wide azimuth, high-fold land seismic data acquired over a fractured formation in the northern part of Saudi Arabia.
Facilities Planning Using Coupled Surface and Reservoir Simulation Models
Authors: Hayder M. Ehtesham , Munoz Alberto , Al-Shammari Ahmed 
Published: May 2011

Abstract
We will discuss issues in developing a production-injection surface facility model to optimize both oil production and water injection strategy in a mature giant oil field. Surface facility modeling was done using commercially available software, which was coupled to Saudi Aramco's in-house reservoir simulator POWERS1. Multiple integrated strategies for analyzing production can be considered with such models. In this paper, we evaluate a facility optimization perspective where many wells are rerouted between multiple gas-oil separation plants (GOSPs) to maintain adequate reservoir pressure to deliver required oil production volumes at the lowest operating cost. We also consider cases where the objective is to evaluate injection allocation strategies, which honors surface constraints, especially surface flow lines’ maximum operating pressure restrictions. Results presented in this paper include a subsurface reservoir coupled surface facility model where proposed strategies are designed to reroute wells from five existing GOSPs producing at high water cuts to two remaining GOSPs for production consolidation. Such strategy allows for an immediate cost savings, since it reduces the number of plants while at the same time producing the required volumes of oil, at reduced water cut, while at the same time maintaining reservoir sweep and recovery since wells which otherwise might have been shut-in are kept on active production. Simultaneously with the option of optimizing oil production, rerouting offers the opportunity to examine water disposal strategies since water can be injected near locations where there might be either a need for additional sweep or simply for reservoir pressure control and redistribution without compromising overall oil production.
We built a surface facility model consisting of five active GOSPs with a few hundred producers and injector (disposal) wells. The surface model is coupled to an over a million-cell reservoir model, containing a sub-set of all the wells available in the POWERS simulation model. Previous work had relied on describing exclusively the production system, leaving the injection system to be handled by POWERS’ well management rules and not subject to optimization or reconfiguration based on reservoir strategies. In this study, both the production and injection model have been constructed and calibrated using the latest available field data and history matched to field performance current at the time of calibration. Model calibration has been assisted by using automated scripts that transfer the relevant production and technical data from a corporate database to the individual model well files and which provide initial estimates for appropriate calibration parameter, such as productivity index, gradient curve matching or reservoir pressure at the time of a rate test, to current or historical field data. Those initial matches are later reviewed and validated on a well by well basis prior to use for prediction runs.
Sensitivity Analysis of Interfacial Tension on Saturation and Relative Permeability Model Predictions
Authors: Abdallah Wael , Zhao Weishu , Gmira Ahmed , Negara Ardiansyah , Buiting Jan 
Published: May 2011

Abstract
Interfacial tension (IFT) measurements of Dodecane/brine systems at different concentrations and Dodecane/deionized water subject to different Dodecane purification cycles were taken over extended durations at room temperature and pressure to investigate the impact of aging. When a fresh droplet was formed, a sharp drop in IFT was observed assumed to be a result of intrinsic impurity adsorption at the interface. The subsequent measurements exhibited a prolonged equilibration period consistent with diffusion from the bulk phase to the interface. Our results indicate that minute amounts of impurities present in experimental chemical fluids "used as received" have a drastic impact on the properties of the interface. Initial and equilibrium IFT are shown to be dramatically different, therefore it is important to be cautious of utilizing IFT values in numerical models. The study demonstrates the impact these variations in IFT have on relative permeability relationships by adopting a simple pore network model simulation.
Petrophysical Evaluation of Shale Gas Reservoir: A case study from Cambay Basin, India
Authors: Tyagi Anil , Abedeen Ainul , Dutta Tanmoy 
Published: May 2011

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.