bluuebunny/crossref_metadata_2025_split huggingface dataset:
Capillary Pressure and Permeability Prediction in Carbonate Rocks - New Methods for Fractures Detection and Accurate Matrix Properties Prediction
Authors: Hulea I. N. 
Published: December 2013

Abstract
Carbonate rocks are known for their heterogeneity and petrophysical complexity. Core-measured permeability values can span orders of magnitude for a given porosity due to the diversity of pore types, as well as the propensity for carbonate rocks to contain (micro)fractures. Multimodal pore throat size distributions resulting from capillary pressure measurements are also an expression of the carbonate rock complexity. These complexities present challenges for accurate prediction of permeability and saturation, and the resulting uncertainties in reservoir models limit the reliability of fluid storage and flow predictions. Special issues arise when core porosity-permeability values are quality checked for low porosities (typically &lt; 5 pu) as errors could have profound effects, especially in "tight" formations. Given these challenges, the goal for this work is a more accurate methodology for permeability prediction in carbonates using pore throat data to develop a quantitative technique that allows differentiation between matrix and fractures properties in porosity-permeability data. Our previous work showed that use of a normalized pore throat radius parameter yields a straight line relationship with permeability data over 6 orders of magnitude. Accuracy of the technique is validated when comparing predicted and measured permeability values from samples from diverse carbonate reservoirs from various periods of geologic time. An important result is that the method can define a valid permeability range, covering a wide range of pore types in carbonate rocks. Permeability values that exceed this valid range are most likely fracture-influenced (artificial or natural). Screening criteria for identification of fractured samples are independently validated by comparing unstressed and stressed permeability data. These newly developed methods are applied to conventional core data, leading to an improved accuracy of the modeled matrix properties.
Laboratory Screening of Corrosion Inhibitors for North Kuwait Oil Fields - A First Step in a Successful Corrosion Inhibition Treatment
Authors: Al-Hashemi Ahmed , Al-Azmi A. , Dabir M. 
Published: December 2013

Abstract
The selection of the appropriate corrosion inhibitor and the adequate injection rate is a important component of a successful corrosion inhibition program of a carbon steel used in an effluent water injection system in North Kuwait oil fields to prevent and control internal corrosion. Before proceeding to field trials, a comprehensive laboratory screening exercise of potential corrosion inhibitors was performed and used as a basis for selecting the best inhibitor(s). This work will highlight the laboratory testing experiments that were conducted to select the best performing corrosion inhibitors for North Kuwait oil Fields. The testing program will particularly consider for the critical operational parameters such as temperature, flow velocity/shear rate, brine chemistry and the range of chemicals injected in the water injection system. Such a wide range of parameters can be simulated using different laboratory testing experiments, including the wheel test, rotating cylinder autoclaves, bench top autoclaves. An illustration of a successful selection of a corrosion inhibitor for the water injection system will be illustrated as a case study.
Modeling of Shale-Swelling Behavior in Aqueous Drilling Fluids
Authors: Maghrabi Shadaab , Kulkarni Dhanashree , Teke Kushabhau , Kulkarni Sandeep D. , Jamison Dale 
Published: December 2013

Abstract
Shale swelling is a serious issue in water-based muds (WBM) as it may lead to stuck pipe, shale sloughing and decreased rate of penetration. Linear Swell Meter (LSM) testing is one of well-known laboratory tests used to characterize shale swelling. This paper describes how the time-dependent swelling response from LSM is modeled to extract characteristic parameters of swelling behavior. The study was performed for different shales with appreciable variation in smectite, illite and Cation Exchange Capacity (CEC). Swelling of these shales in WBM was investigated using different salt concentrations, mud weights and viscosities of the fluids.
Shale swelling as a function of time was modeled in a novel way as %S(t) = A *[f(B*t)+C*g(t)] where %S(t) represents swelling at time t. The equation was derived after combining first order kinetics term as f(B*t) with filtration loss term based as C*g(t). Thus, A represents saturation swelling volume, B represents first-order rate of swelling and C is filtrate loss rate parameter. The model fits well to experimental data with R2 &gt; 0.97 for all shale-fluid combinations investigated which was used to extract the characteristic parameters.
Saturation swelling volume, A, increased with an increase in CEC of the shale. In addition, A decreased linearly till a critical salt concentration in fluid was reached and then flattened out with further increase in salt concentration. Such behavior conforms to osmotic transport of water through shale. It was observed that A was independent of mud weight and fluid viscosity; however B was observed to increase with a decrease in viscosity which may be interpreted as result of diffusion phenomena governing swelling rate. Filtrate loss rate parameter C was estimated to be between 0 and 1 in most of shale-fluid combinations studied. Information obtained from parameters A, B and C can allow us to optimize WBM formulations for shale that can save cost and time.
Case Study of H2S Dispersion at Exploratory Well Test using CFD Tools
Authors: Monjardim Vitor , Rocha Sandra , Piasseski Diogo 
Published: December 2013

Abstract
During the Well Test operation, critical information about the reservoir is acquired, allowing its characterization. In order to perform this activity and due to storage problems, all fluid produced at this exploratory phase is disposed to the atmosphere by burners. In some occasions the gas flare can go off, dispelling the gas without burning. It is called "cold flaring" and depending on the reservoir this might be a problem due the concentration of hydrogen sulphide (H2S) on the gas phase and environmental conditions, such as wind speed and direction. The H2S is a toxic and colorless gas, which is heavier than the air and soluble in both water and hydrocarbons. The limit of exposure is 10 ppm in atmosphere for an 8 work hours.
The aim of this work is to present and analyze different case studies, varying in line H2S concentration, flow rate, wind speed and wind direction, using computational fluid dynamics techniques. The software FLUENT® was used to run 15 different situations, with 48 simulations each, in order to determine safe conditions to flow the well.
Three different types of mesh with about 280000 cells each were used, depending on the wind direction. In each one of the simulations, the H2S plume with 10 ppm was analyzed and classified if it could be hazardous for the rig environment or not. As a result of this project, three charts were created showing the safe zones of operation depending on the gas and environmental conditions. After this study, several wind conditions that were considered dangerous are now safe, as example cases with high flow rate and low H2S ppm or low flow rate and high H2S ppm, reducing the down time due environmental conditions, ensuring that the work is being done in a safety zone.
Correlation of Porosity Uncertainty to Productive Reservoir Volume
Authors: Norman Charles Darrel 
Published: December 2013

Abstract
Monte Carlo simulations demonstrate that probabilistic models of hydrocarbon volumes should correlate the degree of porosity uncertainty to the productive volume of the reservoir. Assessments that fail to model the relationship between productive volume and porosity uncertainty may create unrealistic resource estimates and valuations.
The findings are applicable to conventional exploration prospects with significant uncertainty of productive reservoir volume, and to unconventional resource developments with high lateral variation in reservoir quality.
Probabilistic models of hydrocarbon volume include an estimate of porosity, defined by a probability density function such as a normal or lognormal distribution. The distribution models the uncertainty around the "average" porosity within the field. If a field is small, the productive volume represents a limited sampling of the reservoir. There is a possibility that the average porosity within the productive reservoir may be very high or very low. If the field is large, there is a greater chance that a high porosity in one portion of the field will be offset by a small porosity in another portion of the field, resulting in a narrow range of uncertainty around the average porosity. Probabilistic models that do not decrease the porosity range as reservoir volume increases may generate results in which a high porosity is applied to a large reservoir volume, resulting in resource volumes and economic valuations that are unrealistically high.
The solution lies in the use of multiple-segment models. If each segment represents a stratigraphic layer, or a portion of the potential productive area, and each segment is assigned the wide range of porosity appropriate for a small field, then increasing the number of productive segments will decrease the range of overall average porosity.
This paper clarifies the definition of porosity uncertainty in probabilistic models, reveals a relationship between porosity uncertainty and reservoir volume, and presents a method that will result in more realistic resource estimates and valuations.
High Resolution Diffraction Imaging of Small Scale Fractures Fields in Unconventional Shale Plays
Authors: Popovici Alexander Mihai , Sturzu Ioan , Musat Iulian , Tanushev Nick , Moser Tijmen 
Published: December 2013

Abstract
Summary
In 2000, shale gas represented just 1 percent of American natural gas supplies. Today, it is 30 percent and the percentage keeps increasing. The technology to drill and fracture the shale formations is now exported to the rest of the world, increasing the national oil and gas reserves in many other countries. The thickness of the shale formations is often just a few hundred feet, so new high-resolution technologies are needed to visualize the structure and the natural fracture distribution and orientation in these thin shale layers. Diffraction imaging can be used to complement the structural images produced by conventional processing - by generating an additional image volume of high resolution unconformities - such as small scale faults, pinch-outs, or salt flanks.
A Case Study of Effective Immiscible Hydrocarbon Injection for Enhancing Oil Recovery in a Mature Oil Field
Authors: Pearce Adrian , Madathil Asok , Blondeau Christophe 
Published: December 2013

Abstract
Total has operated an oil field, offshore Abu Dhabi, since 1972 and, after nearly 40 years of production, the major Lower Jurassic reservoir, has one of the highest oil recovery factors in the UAE owing to a strong aquifer pressure support and a successful tertiary recovery process. After 16 years of non-miscible gas injection, this EOR technique has significantly improved oil recovery and also brought valuable lessons.
The purpose of this paper is to present the practical challenges encountered and the solutions developed to address the full field tertiary gas injection scheme. Around 28% of the production since field-wide application of the EOR technique has been attributed to this immiscible process.
Gas injection dynamic behavior is much more sensitive to reservoir heterogeneity than water injection. A more detailed geological and reservoir model was required along with a gas tracer campaign to model properly the well response to the gas injection. Gravity appears to be the main factor controlling the macroscopic sweep efficiency.
As the full field efficiency is highly dependent on the gas management strategy, an extensive monitoring is required to maximize tertiary oil gains and avoid surface bottlenecking. An analytical methodology was developed to forecast oil gains and to allocate the gas in the best sectors.
From the beginning of the project, incremental oil gains are in line with the initial objective and have confirmed the added value of immiscible tertiary gas injection in a mature field.
The gas injection will continue in order to pursue the objective to maximize the ultimate recovery of this field by implementing innovative technical solutions. This requires constant vigilance, sound day-to-day reservoir and well management as well as prioritizing tasks with operations’ staff on a mature platform with competing processes.
Steering with the Multifunction LWD Tool Achieves Optimum Results in High Structural Uncertainty Field in Egypt
Authors: Swire P. , Badr Y. , Ramadan Z. J. , Khattab T. , Siam M. M. , Dolan J. T. , Samir E. , Khattab A. 
Published: December 2013

Abstract
The high structural uncertainty present in a field in Egypt required special logging-while-drilling (LWD) measurement specifications to achieve economically satisfying production results. East Zeit Oil Company (Zeitco) was targeting an oil-bearing sandstone reservoir that is characterized by the presence of subseismic faults and high structural uncertainty. This uncertainty ranges from 6° to 23° in structure dip, which makes drilling successful horizontal wells in this reservoir challenging. A well with a horizontal penetration envelope from a minimum 500 ft measured depth (MD) to an optimum 1,600 ft MD was planned for this reservoir to make the well economic. Steering in such a challenging reservoir required having realtime measurements as close as possible to the bit to make the required real-time decisions. A real-time density image and with other azimuthal data were the primary measurements used in steering this horizontal well. Being used with a rotary steerable tool, the multifunction LWD tool provided density image at only 39 ft behind the bit, which was crucial for the success of the well. The well was successfully drilled with 100% exposure inside the sandstone reservoir with 1,532 ft MD horizontal penetration. In addition, well testing results indicated a natural flow of 2,000 BOPD, which made this well the highest oil producer in the field.
Construction of Bulk Handling Facilities for Production Chemicals in S&EK, WK and NK Areas
Authors: Awan Mukhtar A. , Al-Khaledi Sadoun 
Published: December 2013

Abstract
Production chemicals are primarily used to treat crude oil to its sale specifications, to minimize process problems, and to treat produced water to meet regulatory guidelines for disposal or injection. Voluminous quantities of various chemicals are used in production operations - Company uses more than 50,000 drums (55 USG standard drums) per year at different locations throughout the field areas. Transferring drums from stores to the facilities, chemicals loading from drums to the tanks, spillages and disposing-off empty drums have been causing numerous operational, health, safety and environmental concerns. Therefore, in line with Company’s policies of enhancing it’s operational & HSE performance, the Company decided huge capital investment (KD 16 Million) for constructing modernized facilities for bulk handling of the production chemicals.
This paper outlines the facilities and associated support systems for bulk handling of the chemicals, eliminating use of the conventional chemical drums (55 USG standard drums). The facilities comprise of the Primary Chemical Storage Facility consisting of ten (10) storage tanks for receiving the chemicals in Road Tankers, and subsequent distribution by specialized road tankers (loading arm conforming to API-RP 1004) to the Secondary Storage Facilities in the Gathering Centers (20 Nos.) located in different field areas. The Primary Storage Facility is provided with loading & unloading pumps, ethernet based Terminal Automation System (TAS), utilities, control room & offices, fire-fighting, safety & public address systems, etc. The Secondary Storage Facilities have been provided at the Gathering Centers, with filling connections, instrumentation/controls, pumping facilities, etc. to the Day Tanks.
Oil Companies normally outsource chemicals handling activities. But our Company decided to build its own facilities - unique of its kind. Knowing that many oil majors in the region do not possess bulk handling facilities of this magnitude and configuration, our facilities could be a model for others. Company carried out extensive work prior to the project, in examining options, payment procedures, inventories controls, tankers selection, safety systems, waste management, etc.
Construction of bulk handling facilities is a landmark that enhances Company’s HSE & operational performance, improves inventories & quality controls, eliminates manual handling, and storage/losses problems.
Application of Different De-Convolution Methods in Well Test Analysis of One Iranian Naturally Fractured Reservoir
Authors: kamalipour Meisam , Shahrabadi Abbas 
Published: December 2013

Abstract
In reality the rate of a production well is not constant and varies in time so the producing responses would be noisy. De-convolution is a method of converting a variable rate distorted pressure profile into the pressure profile for an equivalent constant rate production sequence. There are two methods used for de-convolving distorted pressure data: Beta De-convolution and material balance de-convolution methods. The application of both methods was tested in well test analysis of a naturally fractured reservoir. The end of well bore storage was estimated by both methods, and then the reservoir data were analyzed by well testing software. The calculated permeability, interaction coefficient and storativity ratio are different in both approaches. The comparison of data shows that the material balance method predicts the pressure response better and is suggested for applying in field cases.
Exception Based Monitoring As A Tool For Real-time Optimisation: How To Prioritise Well Interventions in Very Large Oilfields
Authors: Crockett Brian J. 
Published: December 2013

Abstract
PROBLEM STATEMENT
Many assets have oilfields with more than a thousand producing wells to monitor, which means that the well analysts find that they can only concentrate on the high producers. The result is that other wells drift out of their operating envelop and in some cases shutdown. With real-time data from tens of thousands of indicators flooding in, the Production team need an exception based monitoring (EBM) system which alerts them when a well is indicating an anomaly, displays it in a prioritised and manageable manner and provides an automated workflow for resolving the issue.
OBJECTIVES
To demonstrate the need for greater visibility and a method for providing a web based portal which can be used to compare real-time data with a set of operating envelope parameters for wells and facilities and detect anomalies as alerts. Show how this was achieved in Oman, Nigeria and the UK.
METHOD Highlight the problems of handling too much data Show how alerts can be sorted, analysed and prioritised automatically Explain how acknowledgement of these anomalies can activate an automated workflow Clarify how optimisations are tracked and escalated
RESULTS The initial deployment of the system produced more than expected anomalies Automatic sorting of the alerts prevented excessive emails being generated Alerts can be grouped geographically Increase in Optimisations and Production
APPLICATIONS
This approach can be used for wells, facilities and data quality.
INNOVATIONS Monitor by exception Prioritise anomalies automatically Provide an automated workflow to track optimisations. It works with Collaborative Work Environments to improve capability
CONCLUSIONS
The deployment of an EBM system gives complete visibility of facilities permitting production teams to focus on optimising critical wells while ensuring that other facilities do not drift towards shutdown.
Implementation of Integrated and Practical Workflow for Fluid Substitution to Improve Seismic Inversion Results: a Case Study from a Carbonate Field in the UAE
Authors: Haggag Mostafa , Chacko Soman , Baloushi Mariam Al , Arafat Mohamed 
Published: December 2013

Abstract
The field under study is structurally and stratigraphically complex, which increases the uncertainties associated with field development. To optimize reservoir characterization using seismic data, seismic inversion (Deterministic, Stochastic and Simultaneous) was planned to be performed using the 3D seismic data covering the field. Given that well log data provide constraints and calibration in the inversion workflow, their quality has a direct impact on the robustness of inversion results. This paper focuses on corrections made to sonic and density log data to make them suitable for seismic inversion.
Sonic and density logs have shallow depths of investigation and are affected by borehole irregularity and filtrate invasion. Errors due to borehole irregularity in the section overlying the reservoir impact two key stages of the inversion process: wavelet extraction using well-seismic ties, and construction of the low frequency or a priori model. Invasion within the reservoir impacts the accuracy of porosities obtained from seismic impedance data. Typically porosity estimation is done using a regression relationship between porosity and acoustic impedance derived from well log measurements. The log impedance data (both velocity and density) are affected by saturation changes related to filtrate invasion which must be corrected for, to obtain a reliable porosity-impedance relationship.
A robust and practical workflow to address log quality issues begins with log data quality QC: identifying zones with missing logs or borehole affected log readings. Shear sonic logs are unavailable for many wells, which limits their use for Simultaneous inversion, and for invasion correction using a rock physics model. We constructed shear sonic logs from compressional sonic logs using a rigorous, iterative process. Gassmann's equation was then used to correct for filtrate invasion effects. Invasion effects were found to change impedance values within reservoir intervals by as much as12 %, which has implications for 4-D seismic monitoring of the reservoir.