bluuebunny/crossref_metadata_2025_split huggingface dataset:
Complex Contaminated Gas Processing Made Simple
Authors: de Oude Matthijs 
Published: July 2015

Abstract
Processing of associated gas has often been considered to be economically non-viable due to the cost and complexity of the installations required to process the gas relative to the value of the gas recovered. The result is that the associated gas is often flared, however, with the growing emphasis on reducing green house gas and SO2 emissions, the processing and recovery of associated gas is becoming increasingly linked to development and maturation of oil reserves.
In some locations the associated gas contains H2S, CO2 and organic Sulphur species, and historically the treatment of these complex gases has required multiple steps to remove the different contaminants. In addition, as the acid gas produced is of low quality, further processing in an acid gas enrichment unit is required to enable recovery of the Sulphur in a traditional Claus and SCOT unit combination. In cases where less than approximately 50 metric tonnes of Sulphur per day is produced, the result can be a relatively complex, costly and energy-intensive process facility.
This presentation describes how Shell has significantly simplified the processing of a complex contaminated associated gas mixture by using an innovative combination of two already proven technologies: Sulfinol-X for integrated all-in-one contaminant removal, and THIOPAQ O&G for biological, single step, low tonnage Sulphur recovery without the requirement for acid gas enrichment.
The strength of this solution lies in the combination and integration of the two technologies. The relevance to the industry is that it enables contaminated, associated gas to be monetized, green house gas reductions to be achieved and oil reserves to be developed in a cost-efficient manner.
Detecting and Correcting Pipeline Leaks Before They Become a Big Problem
Authors: Cramer Ron , Shaw David , Tulalian Robert , Angelo Pabs , van Stuijvenberg Maarten 
Published: July 2015

Abstract
Timely pipeline leak detection is a significant business issue in view of a long history of catastrophic incidents and growing intolerance for such events. It is vital to flag containment loss and location quickly, credibly and reliably, for all green, brown field critical lines in order to shut down the line safely and isolate the leak. Pipelines are designed to transport hydrocarbons safely; however, leaks have severe safety, economic, environmental and reputational effects.
This paper will highlight robust, reliable and cost effective methods, most of which leverage real time instrumentation, telecommunications, SCADA, DCS, and associated online leak detection applications.
The purpose of this paper will be to review the underlying Leak Detection business issues, catalogue the functional challenges and describe experiences with available technologies. Internal and External techniques will be described, including basic rate of change of flow and pressure, compensated mass balance, statistical, real time transient modeling, acoustic wave sensing, fiber optic cable (distributed temperature, distributed acoustic sensing) and subsea hydrophones. The paper will also describe related credibility, deployment, organizational and maintenance issues with an emphasis on upstream applications.
The scope will include leak detection for pipelines conveying various flowing fluids – gas, liquid and multiphase flow. Pipeline environments will include subsea and onshore.
Advantages, disadvantages and experiences with these techniques will be described and analyzed.
Thermodynamic Description of Organic/Inorganic Interactions in TSR Reservoirs
Authors: Richard Laurent , Uteyev Rakhim , Peters Henning 
Published: July 2015

Abstract
Although thermochemical sulfate reduction (TSR) is an irreversible process, it can be demonstrated that many reactions involved in TSR occur at or near equilibrium. This applies not only to minerals and formation waters, but also to hydrocarbons and organic sulfur compounds (OSC) in crude oils and condensates. The metastable equilibrium approach pioneered by Helgeson et al. (1993) is here extended to construct a thermodynamic model of TSR which allows to calculate compositional changes in the water-rock-hydrocarbon-gas system as a function of reaction progress. Using oxygen fugacity as a redox variable to describe the stability relations among minerals, formation waters, and hydrocarbon and organic sulfur species in petroleum, it is shown that the redox state of the water-rock-hydrocarbon-gas system progressively shifts with increasing reaction progress from reduced conditions (under which petroleum is stable), towards more oxidizing conditions imposed by the anhydrite-calcite-sulfur assemblage (and under which pyrobitumen and elemental sulfur may form). This change in redox conditions during TSR appears to be consistent with the observed increase in the aromatic fraction of crude oils during TSR. The results of the speciation calculations compare favorably with compositional data reported in the literature for reservoired oils affected by TSR. Geochemical parameters which have been compared include saturate/aromatic ratios, organic sulfur contents, and concentrations of dibenzothiophenes of crude oils, as well as the CO2/H2S ratio of the gas phase.
Process Safety Information Management
Authors: Okshiev Askhat , Alteneder Will 
Published: July 2015

Abstract
OSHA Process Safety Management Program refers to a set of requirements for managing hazards associated with the processes using highly hazardous chemicals, such as toxic, reactive, flammable or explosive substances. The current hydrocarbon production and processing technologies make Process Safety Management (PSM) Program a critical component for safe operation of refining ventures and gas processing plants.
Process Safety Information (PSI) can be considered the keystone of PSM Program. In order to be in compliance with the OSHA PSM Program the process safety information shall include:
Information pertaining to the hazardous chemicals used or produced by the process; Information pertaining to the process technology; Information pertaining to the equipment in the process.
The objective of this paper is to demonstrate that Tengizchevroil effectively manages some of the Process Safety Information key components at Tengiz field (Kazakhstan) to ensure safe and controlled field operation, as well as to share lessons learned.
New Application of Streamline Simulation for Gas Displacement Processes
Authors: Nagib Mohamed , Burns Alan , Ingham Derek , Pourkashanian Mohamed , El-Banbi Ahmed H. 
Published: July 2015

Abstract
Performance evaluation of miscible and near-miscible gas injection processes is available through conventional finite difference (FD) compositional simulation. The Finite-difference method is widely used for solving large-scale multiphase displacement problems (e.g. displacement of oil by water/gas in heterogeneous petroleum reservoirs). While FD simulation has many advantages, it also suffers from some disadvantages. These include numerical dispersion, grid orientation, small time step size and excessive computation time. However, and specifically for compositional simulation, low-resolution compositional simulation is adversely affected by numerical dispersion and may fail to represent geological heterogeneities adequately, while high-resolution simulation may be expensive in computation time. The number of fluid components can possibly be reduced but only at the price of less accurate representation of phase behavior.
Streamline methods have been developed in which fluid is transported along the streamlines instead of the finite difference grid. In streamline-based simulation, a 3D flow problem is decoupled into a set of 1D problems solved along streamlines, reducing simulation time and suppressing any numerical dispersion. Larger time steps and higher spatial resolution can be achieved in these simulations. Streamline-based reservoir simulation, being orders of magnitude faster than the conventional finite difference methods, may mitigate many of the challenges noted above.
In this paper a detailed comparison is given between the results of conventional FD simulation and the streamline approach for Gas Displacement processes (including miscible processes). Different sensitivities on several resolutions of the dynamic grid is presented. Finally, guidelines are given on how streamline can be potentially used to good effect for Gas displacement processes.
Tengiz Well Performance Forecasting Using Wellbore Transient Flow Modeling
Authors: Ekweribe Chiedozie , Choi Suk Kyoon , Dunger Darrin , Macary Sameh , Howery Randy , Popp Nick , Svyatov Aidar 
Published: July 2015

Abstract
The Tengiz field is a giant oil field producing 530 thousand BOPD from about 70 naturally flowing wells. Continued reservoir pressure depletion and the current surface gathering system pressure have necessitated the need for better prediction of the onset of liquid loading and consideration of mitigation strategies. Active surveillance programs and system integrity efforts have contributed to frequent well shut-ins and some challenges during well restarts. Additionally, the flow back of higher density drilling and completion fluids is becoming more difficult, especially in low pressure areas of the field, and in wells experiencing large fluid losses during drilling or workover.
Steady-state tools are used extensively for well modeling and production forecasting in Tengiz, with historically good results. However it was realized that the steady-state models would be unable to predict unstable production behavior expected to come with continued reservoir pressure decline. Hence, the asset team decided to use a transient flow simulator for a better understanding of these conditions.
This paper describes the selection of the candidate wells, calibration and validation of the transient models and the design of a representative ‘hypothetical’ well which was used to evaluate the minimum conditions for well flow during normal well operations as well as restart pressures post well shut-ins. The impact of various factors including wellhead pressure, productivity index (PI), reservoir pressure, water cut, gas-to-oil ratio (GOR), tubing size and well deviation on loading conditions were evaluated. The study results have provided invaluable information to evaluate mitigation options for liquid loading.
Screening Different Water Alternating Carbon Dioxide Injection Scenarios to Achieve to the Highest Macroscopic Sweep Efficiency in a Non Fractured Carbonate Reservoir
Authors: Bagrezaie M. A. , Pourafshary P. 
Published: July 2015

Abstract
Miscible gas flooding using carbon dioxide provides us excellent microscopic displacement efficiency in different mature oil fields. Due to the limitation of CO2, optimization of CO2-EOR process to reach to the best macroscopic sweep efficiency is an essential problem. Unfavorable mobility ratio and gravity segregation lead to viscose fingering and gravity override. Hence, areal and vertical sweep efficiencies decrease due to the early breakthrough of the injected gas. Different approaches are applied to change the injection scenario of the gas to control the mobility ratio and gravity effects. A comprehensive approach is needed to select the best scenario and optimize it to achieve the highest recovery in an economical manner.
Different scenarios of water alternating carbon dioxide injection such as TWACO2 (Tapered Water Alternating CO2), WACO2 (Water Alternating CO2), SSWACO2 (Selective Simultaneous Water and CO2), and SWACO2 (Simultaneous Water and CO2) can be selected as candidates for the EOR operation. In this work, these scenarios were simulated and studied for a non-fractured reservoir. The simulation outcomes were coupled by an economical model and compared to the pure water and CO2 injection to specify the appropriate and optimized injection method to gain to the highest Net Present Value. Hence, by this method, the necessary amount of the injected gas and water were also optimized for the best scenario. By our simulations, we found that SWACO2 injection increased the total recovery compared to the primary recovery by 25.4 percent which was the highest. The achieved NPV was lower for this method compared to TWACO2. Hence, we recommended TWACO2 as the best method and we optimized it for application in the field.
Experimental Investigation of Gas Lift Instability and Dynamic Regulation to Control It
Authors: Larsen Christer Andre , Asheim Harald Arne 
Published: July 2015

Abstract
The idea explored is that gas lift may be stabilized by imposed oscillations. This has been experimentally investigated in a scaled-down facility where water is lifted by air. An air-tank provides compressibility emulating a gas filled annulus. Depending on pipe dimension, injection rate and tank volume, the flow may be stable, or oscillate similarily to casing heading in full-size wells.
To control natural oscillations, their dominating frequency was firstly determined. Destructive interference was then imposed by cyclic variation of either the downhole injection valve, or the tubing outlet valve. By injection valve regulation, the flow was stabilized and 40% higher liquid rate obtained. Outlet choke regulation also stabilized the flow, but rate improvement less, up to 13%.
Scaled-down facilities should be viewed with sobriety. However, the facility appears to exhibits static and dynamic behavior similar to real wells, so the experimental results may be lent some credibility. This may provide a new and simpler approach to control of gas lift instability.
Karachaganak, Integrated Reservoir Studies on a Giant Field
Authors: Albertini C. , Bigoni F. , Cominelli A. , Della Rossa E. , Francesconi A. , Tarantini V. 
Published: July 2015

Abstract
Karachaganak Field, a Permo-Carboniferous carbonate platform, is a retrograde gas-condensate-oil reservoir located in the Pricaspian Basin. The field, in production since 1985, holds about 9 Bbls of oil and gas condensate and 48 Tcf of natural gas. Historically, the reservoir properties distribution has been debated because of both the complex depositional setting and the strong diagenetic overprint. These uncertainties have been assessed in the present study by analyzing and integrating the vast amount of geological and production data with the target of building a history matched reservoir model.
Seismic facies analysis, integrated with analogues outcrop and core and log data, reveals different geological contexts that ranges from platform interior bedded deposits to aggrading mounds, prograding clinoforms, slopes and basin sediments. Different Depositional Regions, characterized by specific petrophysical characteristics, as estimated from core, log, Well-Tests, PLT and production data, were defined.
The study, performed through an iterative process between geological and numerical models, allowed the definition of geologically meaningful interpretations of the complex dynamic behaviors. Different critical issues were better addressed by Depositional Region: quantity and magnitude of the enhanced permeability related to micro-fracturing and vugs, rock matrix permeability scale factors from plug to whole core, geological meaning and impact of sealing barriers, dolomite estimation and modeling, mound size range and modeling. A "best estimate" reference model has been thus defined and a very good history match achieved.
The uncertainties of the field have been then investigated considering the achieved history match as the benchmark. Starting from the reference model the petrophysical characteristics of the different Depositional Regions have been changed far from the history matched wells at an estimated threshold distance not perturbing the history match. Low and high scenarios models were thusly defined. These represent possible alternative "end members" consistent with the geological data and still endorsed by the history match.
Characterization and Modeling Challenges Associated with Fracture and Karst (Non-Matrix) in the Margin Area of a Carbonate Reservoir
Authors: Medekenova Alfiya , Jones Gareth D. 
Published: July 2015

Abstract
Non-matrix features in the margin area of a carbonate reservoir contribute significantly to field in-place volumes, production rates, and recovery. These features vary in size and shape, but exhibit distinct behavior compared to tight matrix rock. Nonmatrix features such as karst can provide significant storage capacity, and well-connected fractures provide high deliverability. These characteristics make production from the margin area attractive. However, extreme heterogeneity of non-matrix features increases uncertainty and requires complex analysis involving data interpretation, advanced characterization, and sophisticated modeling in order to estimate future production performance.
During the initial field development stage, data interpretation is frequently limited by data acquisition capabilities. Data collection associated with non-matrix features can be challenging, often leading to less than optimal data sets. The scale difference among data gathering techniques further increases the gap between interpretation and full-field modeling. Data integration, along with the use of analogs and concepts, helps to bridge data gaps and improves confidence when modeling field-wide non-matrix heterogeneities.
Advanced approaches, such as dual porosity / dual permeability dynamic modeling enhance ability to evaluate both matrix and non-matrix properties. Once developed, the model is calibrated by comparing simulation results to available dynamic data. As part of the modeling workflow, uncertainty analysis is conducted to identify and evaluate key reservoir properties that could impact in-place volumes and ultimate field recovery. Through collaboration and integration of geoscience and reservoir engineering workflows, it is possible to create a well characterized and calibrated model that is capable of testing key uncertainties against a range of development concepts.
Do Not Let Temperature Transients Hinder Your Build-up Pressure Interpretation – Proper Gauge Placement in Highly Productive Reservoirs in Well Testing Operations
Authors: Sidorova M. , Theuveny B. , Pimenov V. , Shako V. , Guzman-Garcia A. G. 
Published: July 2015

Abstract
Quality of well testing in highly productive reservoirs directly depends on the pressure-gauge placement in the wellbore. This paper documents the impact of the placement of downhole gauges on pressure transient analysis (PTA) for high-productivity reservoirs. The article illustrates cases where this late-transient behavior is strongly influenced by temperature effects, which can lead to significant errors if not considered during the interpretation process.
Although the correction of measured pressure to datum is possible by proper modeling of the influence of non-isothermal effects on the test string and the produced fluids caused by temperature changes, it is preferable to avoid this situation by suitable gauge placement. This greatly facilitates a more accurate interpretation of data using PTA with a reduced uncertainty in the definition of the appropriate reservoir model to use. Proper modeling during the test design of these temperature effects on the correction of pressure to datum also allows the determination of the resulting uncertainty pressure variations and the selection of the optimal test-string design, with consideration made to the expected temperature changes, fluid present in the wellbore, and range of productivity. Reconstruction of pressure is also possible despite a high level of resulting uncertainty.
A workflow for reconstruction of pressure data taking into account temperature effects is proposed. We emphasize that such corrections cannot substitute the correct pressure measurement for successful well-test data interpretation. Present gauge technology allows proper test design and correct placement of pressure and temperature gauges in close vicinity of the interval of interest, to avoid or minimize potential problems related to the reconstruction of the measured pressure to datum.
An Improved Method for Estimating Volumetric Sweep Efficiency of Low Salinity Water Injection
Authors: Al-Shalabi Emad W. , Sepehrnoori Kamy , Pope Gary 
Published: July 2015

Abstract
This paper investigates the effect of low salinity water injection (LSWI) on both oil displacement and volumetric sweep efficiencies. A new definition of mobility ratio is proposed and shown to correlate with volumetric sweep efficiency better than other definitions in the literature. A quarter 5-spot field model was created by upscaling recently published coreflood experiments. Simulations were performed using the empirical low salinity injection model implemented in the UTCHEM simulator. The volumetric sweep efficiency for various seawater dilutions was estimated by adapting a fractional flow method and a tracer method for this purpose. The fractional flow method and the tracer method were consistent in estimating the volumetric sweep efficiency. Moreover, an improved estimation of volumetric sweep efficiency was possible with the proposed mobility ratio definition, which applies in the tertiary mode and physically makes more sense compared to other definitions in the literature. In addition, the maximum incremental oil recovery was achieved at the 10 times diluted seawater injection cycle with is consistent with other studies in the literature. Next, the injected number of pore volumes for each of the seawater dilutions was optimized. The optimum was found to be two pore volumes of injected seawater dilutions.
Application of the Extended Dynamic Material Balance Method to a Super Giant Carbonate Oilfield
Authors: Istayeva Ultay , King Gregory 
Published: July 2015

Abstract
In this paper, we discuss the use of the dynamic material balance (DMB) method to a super-giant carbonate oilfield. The principal advantage of the DMB method, in contrast to the conventional material balance (CMB) methods, is that well shut-ins are not required for the application of the DMB method. While the fundamental assumptions of material balance are still applicable, we extend the DMB method described in the literature in several important ways. These extensions include:
The use of pressure dependent oil formation volume factor (FVF), Bo, including a pressure dependent oil compressibility, co The use of pressure dependent (net effective confining stress) formation compressibility, cf The use of a revised method for estimation of the original-oil-in-place, OOIP
Due to the significance of a super-giant oilfield to the operator's portfolio, well shut-ins are routinely performed in the field and stabilized, static shut-in pressures, though not required for the application of the DMB, are commonly collected. Consequently, we are in a position to compare the results of the DMB predicted pressures to field measured pressures. In general, these comparisons are very favorable, and they will be presented and discussed in the paper.
In addition to the use of the DMB for original-oil-in-place (OOIP) estimates, we have observed that trends in the DMB plots can be used to diagnose pre-/post- workover performance. Therefore, we can use the DMB method to determine the success/failure of well interventions for improving the well productivity and for adding connected in-place oil to the wellbore. Our experience with this application of DMB will also be discussed in the paper.
Finally, we use this paper as a case study for the application of the DMB method to a producing oilfield.