bluuebunny/crossref_metadata_2025 huggingface dataset:
Controls on Mannville Coalbed Methane Production in Fort Assiniboine, Alberta
Authors: Bearinger D. , Majcher M.
Published: February 2011

Fort Assiniboine is a commercial Coalbed Methane field in central Alberta, Canada with over 200 multilateral horizontal wells in the Upper Cretaceous Mannville coal. The Mannville coal seams in this area are under-saturated. Therefore the reservoir's ability to dewater the coal through the fracture fabric to establish a gas phase is key to improving permeability to gas within the fracture system and thus achieving economic gas production rates. There is a wide range of production rates seen across the field. The multiple variables that affect gas production can be divided into a two main categories, wellbore parameters and reservoir parameters. Some of these variables were sufficiently straightforward to establish while other variables, such as permeability, are not as easily ascertained in a fractured coal system having multiphase flow. Field wide data was collected from core, wells, geological and geophysical mapping and production data. The information was compiled and analyzed in order to determine the major controls on gas production rates.
Integrated Monitoring Radon and NORM Scale: HSE Well Surveillance Case Study
Authors: Nengkoda Ardian , Hajri Mohd , Kindy Azzan , Bulushi Abdulwahab , Yazeedi Zeyana , Velagapudi Ravi Kiran , Nicol Barry
Published: February 2011

Processes of oil production, gathering, transportation are some times accompanied by scaling of radioactive materials (NORM). As an integrated approach to identify the Radon and NORM scale as flow assurance issue, a campaign of Radon monitoring, Barium and Strontium ion analysis from produced water potential lead to NORM scale have been conducted starting from well testing and in both onplot-offplot of the oil gathering station. Chemical composition of NORM scales strongly depend on chemical composition of produced waters. Presence of considerable amount of radioactive materials on technological equipment during production and treatment of oil, and gas may lead to personnel irradiation exceeding allowable levels and creates potential hazard to environmental pollution. The role of radon and its decay products in pollution of environment and internal personnel irradiation was not practically studied. Liberation of radon with decay products from scales and their entry into atmosphere may lead to radioactive pollution of environment, which increases the risk of internal personnel irradiation. This technical paper explained how to monitor effectively potential NORM and the intensity of radon accumulation in X field Petroleum Development Oman. During well testing or intervention, the equipment of wells radiobarite precipitates on impellers of electric centrifugal pumps, tubing inside surface in the form of white films with yellowish tint. Thickness of scales on tubing surface achieves 3 mm. In long-run operation radiobarite in electric centrifugal pump is able to clogging up. As a result of this well surveillance, Radon, Barium and Strontium analysis from produced water are really helpful in predicting NORM potential.
HySWEET® Process: An Improvement in Energy Efficiency
Authors: Shah Virenkumar , Cadours Renaud , Weiss Claire , Benquet Christophe
Published: February 2011

Removing mercaptans from sour natural gas has always been considered as a challenge. This is becoming an even more important issue with the global trend towards more stringent commercial gas specifications. Amines have been extensively used because of their ability to meet the most severe H2S and CO2 specifications and their very high acid gas selectivity over hydrocarbons, but present very limited mercaptans removal performances. An additional treatment step is required to achieve the total sulfur specification in the exported gas. Hybrid solvents are more efficient in removing mercaptans, but may have the disadvantage of poor acid gas selectivity over hydrocarbons, resulting in hydrocarbon losses with the separated acid gas.

Total, taking advantage of its extensive know-how and experience in gas sweetening with amine mixtures, has developed a new hybrid solvent formulation allowing simultaneous absorption of acid gases and of mercaptans, with limited co-absorption of hydrocarbons. The HySWEET® process using the new hybrid solvent is in operation at the Lacq plant in France since 2008. More than half of the gas production is now treated with this new hybrid solvent, allowing to achieve not only higher global mercaptan removal but also to reduce the overall energy consumption compared to the use of the HiLoadDEA process.

This paper emphasis on the energy gain that can be achieved by using the HySWEET® process compared to the conventional HiLoadDEA process. A pilot plant study was carried out to compare the regeneration heat duty requirement of the new HySWEET® process with that of the HiLoadDEA process. This study has actually demonstrated that under similar conditions the HySWEET® solvent requires up to 15 % lower reboiler heat duty compared to the conventional amine solvent. These results have been confirmed during industrial operation of the HySWEET® process at the Lacq plant.

This paper also reminds the results of the techno-economic study carried out to evaluate the potential gain achievable by the implementation of the new hybrid solvent. The study lead to identify the application cases for which the new hybrid solvent will allow an economic and complete mercaptan removal without any additional treatment, and a perspective of reduction of the additional treatments for the other cases.
A Case Study of Seismic Anisotropy Analysis on Multi-Azimuth OBC Seismic Data in an Offshore Carbonate Oil Field, U.A.E.
Authors: Ikawa Hidemasa , Mercado Gary
Published: February 2011

Fractures can be observed in micro or macro scale at outcrops and many oil/gas reservoirs can be fractured as well. A good understanding of the fracture network is hence critical for reservoir development since it could have significant impact on fluid flow. Full azimuth 3D seismic data provides a means of detecting and characterizing fractures before drilling. Seismic anisotropy investigation for fracture detection has been carried out in a carbonate oil field located in offshore United Arab Emirates (U.A.E). Target reservoirs are lower cretaceous carbonates mainly consisting of limestone with alternating porous and dense intervals which become dolomitic with depth.

A large 3D-2C OBC seismic data sets was acquired over this giant oil field with orthogonal patch geometry covering all azimuths in 2001. The seismic data was reprocessed in 2006 to improve mainly pre-stack data quality and maintain azimuthal integrity. Velocity and amplitude analysis by ellipse fitting for the azimuthal anisotropy intensity and the direction have been conducted on seismic super CMP gathers, PreStack Migrated (PrSTM) partial stacked data and azimuthally picked velocities. A multi-line walkaway and walk-around VSP survey from a single point of well control was also used to analyze and to verify 3D seismic results.

The VSP amplitude and AVOAz results around the well show harmonic amplitude variation with offset and azimuth. However, amplitude analysis on partial stack data shows relatively high seismic anisotropy intensity especially in noisy data areas and the direction is not consistent with the other results. The azimuth direction of partial stacked amplitude is close to the receiver line orientation and thus appears susceptible to acquisition geometry and processing applications. On the other hand, all velocity analysis results show a NE-SW high velocity anisotropy trend. This is consistent with the regional ZAGROS stress field which also has a NE-SW as SHmax, consistent with FMI and core interpreted open fracture data. Six core and FMI data sets were used in this study to verify the results. The velocity analysis result is consistent with the core & FMI data at 5 of the 6 well locations in terms of the azimuthal direction. These results of this study highlight the importance of reviewing multi-sources of information when available, evaluating pros and cons of the datasets with specific attention paid to data volume, noise sensitivity and resolution.
Uncertainty Management in a Major CO2 EOR Project
Authors: O’Dell P. M. , Lindsey Kirby C.
Published: February 2011

Occidental is the operator of a large turbidite sandstone reservoir in California that has progressed through primary depletion, limited gasflooding, and extensive waterflooding. A fraction of the reservoir is shut-in at this time due to uneconomic water cut. Oxy is currently evaluating a miscible CO2 injection project in this light oil reservoir.

Although a CO2 injection project has the potential to significantly increase oil reserves and extend productive field life, the project includes significant technical and economic challenges. This paper describes the evaluation of subsurface uncertainties, including the use of a two stage design of experiments approach to choose optimal operator choices, regardless of subsurface uncertainties, and preparation of probabilistic production forecasts for project valuation. The steps in generating a robust model, discretization study, tornado analysis, uncertainty analysis, and generating forecast type curves are described.

Operator choices and subsurface uncertainties each have significant impact on oil recovery, CO2 utilization, and project valuation. Though fundamentally different, both must be included in any uncertainty analysis. The authors believe the two step approach is a novel technique to evaluate operational trade-offs and find optimal solutions.
Asphaltene Studies in On-shore Abu Dhabi Oil Fields, PART II: Investigation and Mitigation of Asphaltene Deposition - A Case Study
Authors: Abdallah Dalia , Al-Basry Ali , Zwolle Simon , Grutters Mark , Huo Zhongxin , Stankiewicz Artur
Published: February 2011

Asphaltene is the heavy component of a crude oil that constitutes a potential problem because of its tendency to precipitate and deposit causing blockage in tubulars, pipelines and surface facilities leading to decline in oil production. There are a number of wells affected with asphaltene in an onshore field in Abu Dhabi and this is likely to increase in the future with the implementation of Artificial Lift (AL) and HC/CO2 gas injection for EOR.

Mitigation strategies in the field have been concentrating on design of remedial solvent treatments in combination with mechanical methods for removal of deposits. The company’s approach has been shifting in dealing with asphaltenes from reactive to proactive by conducting studies to: understand asphaltene stability in the different fluids, model the behavior across the whole field, look at the effect of HC/CO2 gas injection on asphaltene stability and finally develop optimal preventative techniques to reduce treatment costs.

The study in this onshore field in Abu Dhabi was conducted on oils collected from different zones. The first part of the study involved analysis of different stock tank oil properties, e.g. API, Sulfur content, Nickel content, asphaltene content and viscosity to look for correlations that can help in identifying the problematic areas in the field. The second part of the study involved asphaltene stability screening tests, e.g. SARA screen, to determine whether the fluids from the different zones are stable or unstable with respect to asphaltene. Live-oil depressurization experiments were conducted on selected wells to determine the Asphaltene Onset Pressure (AOP) at different production conditions using solids detection system with Near Infra-Red (NIR) and High Pressure Microscopy (HPM) for visual confirmation of asphaltene particles. The data from the live-oil testing was then used to calibrate Shell’s thermodynamic model which was then used to investigate the effect of changes in process conditions on asphaltene stability phase envelopes. Results of thermodynamic modeling can be applied on the full field which will aid in developing appropriate inhibition and remediation strategies to deal with the asphaltene challenges.
Asphaltene Studies in on-shore Abu Dhabi Oil fields, PART III: Optimization of Field Chemicals for Remediation and Inhibition of Asphaltene Deposition
Authors: Abdallah Dalia , Bazuhair Mohamed , Zwolle Simon , Grutters Mark , Ramanathan Karthik , Artur Stankiewicz
Published: February 2011

The selection of a chemical solution to asphaltene challenges is an integral part of the flow assurance strategy, and has direct impact on both CAPEX and OPEX. The chemical selection process includes a detailed analysis of deposits, measurements of crude oil properties and various stock tank liquid tests, which are essential input into the development of the most appropriate inhibition and/or remediation strategy. The success of the chemical treatment strategy is a collaborative effort between operations and technology experts.

In an onshore field in Abu Dhabi, routine clean-up jobs to date consist of diesel solvent as a carrier mixed with a dispersant chemical in approximately 80:20 proportions. However, the field observations indicate that such an approach provides often limited effect and sometimes can be detrimental for the well due to fluid incompatibilities. Laboratory tests on deposits collected from this field, combined with Shell’s extensive experience in the area of asphaltenes prevention/remediation led firstly to identification of an alternative aromatic-rich solvent. In addition, better performing dispersant chemicals than previously used were identified that could increase the overall efficiency of the cleaning jobs (soaks, washes).

In order to reduce the frequency of clean-up operations for wells with severe asphaltene problems, continuous application of chemicals (inhibitors) has been considered. Asphaltene inhibitors may not completely prevent asphaltene precipitation but may significantly "delay" the process of deposition. Lab inhibitor testing was performed on crude oil samples collected from the Abu Dhabi field and the performance of the chemicals with respect to their concentration was evaluated. The best inhibitor from the lab testing will be applied in a field trial where the dosage is optimized following a proper surveillance plan to monitor the chemical effectiveness.
Complex Laboratory Method of Reservoir Properties Determination for Anisotropic Layers at the Flowing of Abnormal Oils
Authors: Kadet V. , Dmitriev N. , Mamedov M.
Published: February 2011

Nowadays, the fields of hard recoverable hydrocarbon reserves are involved more often into reservoir engineering process. The problem of recovery is often connected with non-Newtonian rheology of oil and complicated reservoir structure. Now the problem of viscous-plastic fluid flows in isotropic reservoirs is studied enough. But, as a rule the real reservoirs show anisotropy of reservoir properties. That's why taking into account anisotropy at the developments of viscous-plastic fluid flows offer both practical and scientific interest.

The present paper represents the laboratory method of combined determination of absolute permeability and limiting pressure gradient for anisotropic reservoirs. The method for determination a structure of absolute permeability tensor and tensor of limiting pressure gradient on the core samples is based on combined usage of two methods. The first of them is the measurements of ultrasonic waves' propagation velocities through the core sample in the various directions. And the second is the measurements of elastic static deformations of the core sample in the various directions. The usage of specified methods allows to establish the fact of anisotropy at first and further to determine the anisotropy type. Then the necessary number of core samples is sawed out from the drill core in the requisite directions in compliance with the anisotropy type for carrying out hydrodynamics researches.

The results of the determination of absolute permeability tensor and tensor of limiting pressure gradient for anisotropic reservoirs are represented. The results confirm tensor nature of limiting pressure gradient and allow to get law of viscous- plastic fluid flows in anisotropic porous media. Within the frame of suggested method it's possible to determine tensors of phase permeability and construct non-linear fluid flows laws.

Taking into account the anisotropy of reservoir properties permits to describe fluid flow distribution more adequate which in turn makes it possible to optimize direction of horizontal well drilling, to rationalize field development system (well spacing) and finally to increase oil recovery.
Hydraulic Fracturing as a Method of Improving Oil Fields Development at the Late Stage
Authors: Mukminov . R. , Mullagalin . Z. , Shayahmetov . A. , Pasynkov . G. , Beloguzov . F. , Shablovskii . V. , Nikitin . N.
Published: February 2011

This report was chosen for the presentation by the Programme Committee SPE for the information examination results, included into the summary. The Society of engineers and oilworkwers didn’t examine the content of the report, so it’s open for alterations and corrections suggested by the authors. The Society of engineers and oilworkers, its’ officials or participants do not necesseraly share ideas of the following report. Reports presented at the SPE conferences are to be examined by editorial committee of the Society of engineers and oilworkers. Copying, leasing or keeping any part of the given report for commercial profit without written permission given by the Society of engineers and oilworkers is prohibited. Prinning the summary of the report of 300 words is allowed; copying the illustrations is prohibited. Summary is to have the reference to where and when the original report was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836 U.S.A., fax 01-972-952-9435.
Integration of Horizontal Well Test Results and Log Data with the Purpose of Improving Field Simulation Model
Authors: Neustroev K.A. , Kostyuchenko S.V.
Published: February 2011

Proposal

This article describes the method of integrated application of horizontal well test result and log data interpretation for refining the simulation model of a specific field. It is stated that the filtration reservoir parameters resultant from the well test interpretation can be more accurate versus the petrophysical model results. Therefore, this method can be useful for underappraised fields and greenfields that do not have robust petrophysical dependencies.

We have formulated and investigated the problem of averaging filtration reservoir parameters in the simulation model to match them with horizontal well test result interpretation. The averaging method has been validated using numerical well test models and subsequent interpretation of synthetic pressure build-up curves. The method of matching simulation model parameters and well test result interpretation can be useful for all fields where horizontal wells are used for development.

The article details the problem of horizontal well test result interpretation at a specific field and describes the uncertainty assessment.
Results of Water-gas Stimulation of the Formation Conducted in OJSK “Ritek”
Authors: Kokorev V. I. , Chubanov O. V. , Akhmadeishin I. A. , Shchekoldin K. A. , Kharlanov S. A.
Published: February 2011

The paper discusses two technologies for implementation of gas methods used in oil field development. - alternating gas-water injection and water-gas stimulation in which combined injection of displacement agents (gas and water) is used.

OJSC “RITEK” is successfully implementing the enhanced oil recovery by means of water-gas injection into the formation.

Water-gas stimulation is stimulation of the oil-bearing formation in which oil is displaced by a maximum possible wide frontal gas fringe followed by water injection. Gas flood ensures high displacement efficiency, while water flood ensures high sweep factor.
Enhancing Efficiency of Steam-Thermal Treatment of Formations With High-Viscosity Oil
Authors: Shandrygin A. , Dinariev O. , Mikhailov D. , Nukhaev M. , Lutfullin A.
Published: February 2011

The studies of the combined method of CHOPS and Cycling Steam Stimulation (CSS) of high viscosity oil reservoirs are described. Technological efficiency of the said stimulation compared with the traditional CSS shown and the main factors that influence the said process determined.

The methods aimed at simulating the non-isothermal multi-phase fluid flow in a formation with wormholes within dual porosity/dual permeability model with parameters expressed as a coordinate function equivalent to the average parameters of the fractal structure described.
Interactive Petrophysical Model of Oilfields with Large Transition Zones Salym Fields Example
Authors: Volokitin Y. , Khabarov A.
Published: February 2011

Many “classical” oilfields in West Siberia represent low- relief structures with long transition zones and presence of moveable water above official oil-water contacts (OWC′s). Development of such “undersaturated” accumulations is complicated by difficulties in prediction of rate potentials for new wells and risks of high initial production watercuts.

Salym Petroleum Development (SPD) company (a 50/50 JV of Shell and Sibir Energy) is successful in developing such fields in the South of West Siberian oil province. This business success is based in part on building an effective and reliable petrophysical model of reservoir rock and fluid distribution.

This was achieved through integration of core, log an production data. At the core of the algorithm is a capillarypressure based model of transition zone interlinked with algorithms of traditional and special log evaluation as well as with models of fluid phase mobilities.
Mannville CBM: Integrated Approach in the Mikwan Area
Authors: Hyland F. , Palmai F. J. , Yu M. , Abaco C. , Ionkina N. , Cox W.
Published: February 2011

Historical analog data indicates that production from Mikwan area Mannville CBM wells can differ substantially from the typical production profile, resulting in significant uncertainty with respect to expected well performance. Encana, through the applied integration of the key disciplines of Geoscience and Engineering, was able to reduce the economic and technical challenges inherent in developing this resource, and optimize the gas production potential from the 100/13-25-36-21W4 Mannville CBM well.

To maximize the drilling success and production potential of the well, specific strategies are employed to optimize the placement of these wells to ensure reservoir access is in the driest portion of the fairway. First, hydro-geological data was considered on a regional level to define the Basin Centered Gas System envelope that defines the Mannville CBM Dry Fairway. Petrophysical assessment was utilized to address the risk associated with water influx from adjacent lithologies and to characterize the coal quality by integrating core analysis with petrographic study data. Through integration of geological and geophysical data the well is placed in an optimal structural setting that promotes nature fracture development leading to enhanced permeability.

The well was subject to several differing completion programs leading to a refinement of completion techniques. In addition, production and production logging methods were used to qualify the completion results.

This paper will demonstrate the successful characterization of the Mannville CBM reservoir in the Mikwan area of Central Alberta. The paper will highlight the integration of these methods to maximize the production potential through a case study of the 100/13-25-36-21W4 well. The lessons to date indicate Mannville CBM well potential can be predicted with some confidence in this Mikwan dry gas fairway area.
Simulation of Deep Coalbed Methane Permeability and Production Assuming Variable Pore Volume Compressibility
Authors: Tonnsen R. R. , Miskimins J. L.
Published: February 2011

One of the horizons of interest for future unconventional resource development is deep (greate than ~5,000 ft) coalbed methane (CBM) production. Unfortunately, coal permeability is highly sensitive to changes in stress leading to the belief of limited permeability in deep coals. However, this conclusion is generally based on the assumption of constant pore volume compressibility of a coal's porosity/cleat system during changing stress conditions.

Modeling the evolution of permeability within potential deep coal reservoirs is highly dependent on this assumption of constant or variable pore volume compressibility. This paper shows how this assumption affects modeled permeability changes and that permeability in deep coals may maintain much higher values during production than previously suggested. Utilizing prior work and data, ideas are reorganized into an alternative view of deep CBM permeability.

The modeled compressibility and permeability results are then applied to the simulation of deep CBM reservoirs to discover the practical difference of the compressibility assumption on a coal's simulated production. Simulations show significant difference in production based on the two assumptions. Application of the simulation results may provide a justification for exploration into deeper CBM reservoirs.
Distance Separated Simultaneous Sweeping: Efficient 3D Vibroseis Acquisition in Oman
Authors: Bouska Jack
Published: February 2011

Distance Separated Simultaneous Sweeping (DS3) is one of a number of techniques developed by BP for efficient land seismic operations and is a new Vibroseis technique which produces independent records, uncontaminated by simultaneous source interference, for a range of offsets and depths which span all target zones of interest. Use of DS3, on a recent seismic survey in Oman, resulted in a peak acquisition rate of 1024 records per hour. This survey employed 15 vibrators, with a distance separation of 12km between simultaneous active sources, recorded by 8000 active channels across 22 live lines in an 18.5km x 11km receiver patch. Broad distribution of simultaneous sources, across an adequately sized recording patch, effectively partitions the sensors so that each trace records only one of the simultaneous sources. With proper source separation, on a scale similar to twice the maximum usable source receiver offset, wavefield overlap occurs below the zone of interest. This yields records which are indistinguishable from non-simultaneous source data, within temporal and spatial limits. The DS3 technique may be implemented using a wide variety of acquisition geometries, optimally with spatially large recording patches that enable appropriate source separation distances. DS3 improves acquisition efficiency without data quality degradation, eliminating the requirement for special data processing or noise attenuation.
Impact of Relative Permeability Hysteresis, IFT dependent and Three Phase Models on the Performance of Gas Based EOR Processes
Authors: Masalmeh S. K. , Wei Lingli
Published: February 2011

In this paper we report on a gas-injection based EOR study in heterogeneous carbonate reservoirs. The focus of the study is on modelling three phase flow, hysteresis and compositional effects on relative permeability for a reservoir with different scales of heterogeneity.

For all gas-injection based EOR processes, numerical modelling requires proper understanding and presentation of phase behaviour, saturation functions and geological heterogeneity. In this study we performed a systematic analyses of the interplay between compositional effects, relative permeability hysteresis, interfacial tension dependent relative permeability and three phase relative permeability models for different gas based EOR schemes (e.g., WAG, SWAG, SIMGAP). The simulation runs were performed using 2D and 3D fine scale sector models. In order to extend the applicability of the results to a wide range of carbonate reservoirs, the study was performed using three different reservoir models with different permeability profiles and different initial water saturation distributions. To quantify the impact of phase behavior, the performance of different injection gases (methane, CO2 and acid gas) was compared. Finally, we also compared the impact different three phase relative permeability models on oil recovery.

To the best of our knowledge, there is no commercial simulator which has implemented the combination of relative permeability hysteresis, IFT dependent and three phase models in compositional mode. Therefore, the study presented in this paper is the first in the literature which investigates the combination of all these effects on the performance of gas injection EOR schemes. The study shows that proper representation of relative permeability hysteresis, compositional effects and three phase models is essential in order to assess the performances of all gas based EOR processes. The study also shows that before embarking on very expensive laboratory work for EOR studies under three-phase flow, simulations should be used to help design the laboratory work in order to focus on the most important parameters that affect fluid flow and hydrocarbon recovery. The simulation work should be carried out using fine grid sector models.
Review of the IPACE Reserves Classification System
Authors: Marsh R. A.
Published: February 2011

Since 1979, Alberta's Energy Resources Conservation Board (ERCB) and other Canadian authorities have been releasing reserves estimates based on the report of the Joint Task Force on Uniform Reserves Terminology to the Inter-Provincial Advisory Committee on Energy (IPACE). This report, while including terms related to petroleum types and recovery methods, defined three main resource/reserve terms; Initial Volume In-Place, Established Reserves (both Initial and Remaining), and Ultimate Potential.

While the IPACE terminology is a simple and useful system, and is well suited to conventional pools, it is not as well suited to continuous accumulations, especially in classifying in-place quantities that are currently being developed from those that have been or those that might be developed in the future. Additionally, its definition of established includes a quantity of less certainty that is not well defined and has been interpreted in several ways. With the increasing importance of unconventional resources, the introduction of newer classification systems by Canadian and international authorities, and the evolving nature of its business, the ERCB began a review of the IPACE terminology.

The review concluded that the IPACE system, particularly with initial established reserves and ultimate potential, is still a very useful classification scheme, especially for resource management, but would benefit from modification to better suit the wide potential of unconventional resources. The most significant potential changes envisaged are the introduction of multiple in-place categories, the alignment of established reserves with "best estimate", and the recognition of established reserves under active development.

Unconventional resources continue to gain importance to the future long term energy supply of Canada and the ability for governments to reasonably classify their full potential is important. Potential modification of the IPACE system recognizes these two issues.
Advancements in Technology and Process Approach Reduce Cost and Increase Performance of CO2 Flow Monitoring and Remediation
Authors: Sweatman R.E.. E. , Marsic S.D.. D. , McColpin G.R.. R.
Published: February 2011

A novel, cost-saving approach combining rapidly-acquired CO2 flow measurements and early-alteration improves CO2 placement, leak detection, and remediation in CO2 enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. The approach is based on field-proven technologies for monitoring CO2 flows and for controlling flows within reservoirs or remediating flows outside of reservoirs. The new low-cost monitoring technology employs reservoir flow induced micro-deformation measurements by three basic technologies—satellite-based interferometric synthetic aperture radar (InSAR), surface and downhole tiltmeters, and differential global positioning systems (GPS). These methods acquire microdeformation data in near-real-time (NRT). This data supports NRT geomechanical inversion analysis that provides 3-D reservoir flow images. Real-time temperature and pressure data from wells instrumented with sensors connected to fiberoptic cables may also be used to better characterize some CO2 flows. The new lost-cost flow control and remediation technology is derived from improvements in flowpath sealants and placement methods that can alter flows both inside and outside of reservoirs.

This monitoring technology has evolved from similar methods proven in other types of secondary and tertiary recovery projects, and more recently in CCS projects, to identify reservoir flows and pinpoint abnormal ones. An example of normal CO2 flow results is presented to show how operators can calibrate flow-prediction software models and make fast decisions to apply flow enhancing methods. These methods improve CO2 sweep efficiency, increase oil production, and better utilize the reservoirs’ CO2 storage capacity. Another example shows the early identification of an abnormal flowpath location that enables timely selection of sealing methods and materials that eliminate unwanted flows from reservoirs with negligible CO2 losses.

The CO2 flow control and remediation technology’s history of field-proven success is described along with recent developments that have improved both material and placement performance. Generic case histories of conventional vs. the proposed new approach are compared to show how the combination of rapidly-deployed, CO2 flow-alteration and monitoring technologies creates synergies that can improve the performance of CO2 EOR and CCS projects while reducing operating costs.
Survey of over 1000 Frac Stage database with Net Pressure in the Barnett Shale. Part 1
Authors: Lehman Lyle V. , Shelley Robert F. , Shah Koras
Published: February 2011

This paper discusses a project of data mining through a database of more than 1,000 frac stages in the Barnett Shale. The database includes fracture pressure and other job data as well as the fracture shape that was mapped by microseismic processes. The original intent of the data mining project was to seek relationships between hydraulic fractures staying in zone and aiding in generating a fracture network as these events relate to net pressure trend. Results from the data mining exercise were revealing. The implications of this work potentially yield answers to questions such as: Can a frac model be developed that predicts fracture network development in a shale?Is using poroelastic-based physics in a model appropriate for shales?Can a model of this type be used to analyze frac data?What is the ultimate value of microseismic mapping in shale reservoirs?

This paper is the first in a series on the database and will answer most of these questions. It will also propose future issues in the development of artificial analysis that may help select fracture network as opposed to planar frac geometry from geological and geographic data.
Productivity Pilot, How to Produce Tight/low Connectivity Reservoir with a Maximum Reservoir Contact Well - A Field Case from Abu Dhabi Offshore
Authors: Al Hammadi Hamdan , Elsaid Mohamed E. , Schaeffner Anne
Published: February 2011

Layer IIB is one of undeveloped layers in an offshore Abu Dhabi. The reservoir has large gas cap with saturated oil rim. Low permeability is the main problem in this layer(less than 10 md). In addition, discontinuity in reservoir leads to scatter discontented oil pools all over the layer. Layer IIB is a thin layer with thickness varies from 10 to 30 feet lead to limit the production area. Lithology is dominated by almost dolomite with no secondary porosity. It was noticed that top Layer IIB is always had better geological properties in terms of porosity & permeability than the rest layer. Many trials were unsuccessful in the past to produce from this layer by using slanted wells and Bull heading stimulation.

The objective from this well is to collect dynamic data to be used in the development plan since the old trials were failed to produce due to tightness of the reservoir. Therefore, propose was made to drill horizontal well with maximum reservoir contact in the thin good part of the reservoir. Top technology was used in Geosteering to insure horizontal section in the good reservoir part. Coil tubing stimulation with diverter was implemented in the open hole horizontal section to distribute the acid in the hole. For the first time, strong acid (with HCL 25%) was used to improve the productivity of the tight rocks around the well. The well was test and produce at rate of 2.5 MBOPD with reasonable GOR and no water cut. The same completion strategy will be used for the upcoming wells in this layer.
Frac Sleeves: Is Milling Them Out Worth the Trouble?
Authors: Wozniak G.
Published: February 2011

Since 2007, EQT has completed over 600 horizontal wells in Eastern Kentucky with multi-stage, open-hole packer systems. Possibly due to the low-pressure nature of the reservoir, EQT has averaged only 53% frac port ball recovery during post-frac flowback. Due to rig restraints, cost concerns, and an unknown potential for production gains, EQT did not elect to immediately mill out the frac sleeves on nearly all of the wells. During 2009, EQT started a frac sleeve millout test program to evaluate the potential production gains due to the removal of the downhole restrictions of the frac sleeves and balls. The candidates were selected based on several criteria, including the well's Estimated Ultimate Recovery (EUR) as compared to its offsets, the type of frac treatment, and the percentage of ball recovery during flowback. When the results from the 10 well test campaign showed measurable production gains, the program was expanded to include 25 additional wells. The gains in reserves from the millouts were calculated by subtracting the previously forecasted reserves from the current expected reserves. The criteria for candidate wells for the 2nd campaign was revised based on the results from the 1st campaign to include the wells' fluid production and the deviation of the upper-most frac port.

Many in the industry are unaware of the potential production and reserve gains from frac sleeve millouts. Six of the 10 wells in the original campaign showed significant daily production gains following millout. Following well optimization (including tubing and plunger lift installation on 3 of the wells), the average EUR from the initial 10 millout wells increased by 119 MMcf, with two wells showing EUR increases of close to 300 MMcf. A well from the second campaign showed an EUR increase of 716 MMcf; other wells showed more moderate increases while some showed no EUR gain at all. After using decline curve analysis, EQT feels confident that the production increases from millouts are incremental gains and not merely accelerated production. Economics run on the project as a whole show significant EUR increases and compelling incremental costs per mcf of reserves added. Based on the well production results, an additional 300 well frac sleeve millout program has been launched and is ongoing.
Acid Stimulation Results of Arab Carbonate Reservoirs in Offshore Field, U.A.E.: 10 Years of Review, How to Prepare the Future Challenges Linked to Stimulation
Authors: Shokry Ahmed F. , Tawfik Osama M.
Published: February 2011

The Upper Jurassic Arab Formation in Offshore Abu Dhabi represent a regressive cycles of sedimentation developed with shoal, laggonal, subtidal and supratidal sediments. This formation includes various types of lithologies along the reservoir column: Anhydrite alternating with Dolomites, limestone of grainstones and mudstones/wackestones.

Matrix Acid stimulation treatments are routinely performed using HCl and it is playing a vital role in developing oil carbonate reservoirs. As around 60% of the oil reservoirs in the world are carbonate with high heterogeneity: improving stimulation techniques/technology is a major challenge to enhance oil recovery and overcome the heterogeneity in such reservoirs.

Stimulation operation results are affected by reservoir heterogeneity. Understanding formation texture in carbonate greatly affects the success of stimulation jobs. Many factors can affect the results of an acid job such as chemicals (acid), mineralogy of the rocks, and the permeability variation through the formation.

Proper Acid placement and zonal coverage are some of the most important factors for successful matrix acid stimulation treatments.

A giant field on production for 40 years is the focus of 10 years of acid job investigations. We evaluated the effect of the acid and identified the main parameters that control its efficiency and maximized well productivity (acid techniques, placement methodology, etc.). This paper will detail the analysis done in 100 wells and the results will show the best techniques deduced from these 10 years of experience. This study aims to improve acid techniques/technology to maximize well productivity, in all reservoirs types and consequently improve oil recovery.
Infra-red Water Cut Meter Field Trial under Transient Conditions
Authors: Nassereddin T. A. , Al Hagin K. , Hariz M. , Melo M. , Raman B. , Helal R.
Published: February 2011

Determination of water and sediment content is required to measure accurately net volumes of actual oil in sales, taxation, exchanges, production allocation and custody transfer. Individual well testing is the most common practice for production allocation in gathering stations; nevertheless some operators tend to collect manual-samples to verify well production. However taking representative manual-samples under transient flow conditions represents a challenge. Therefore a technology capable of providing an accurate water measurement under such conditions is of high importance in the Oil and Gas industry. An oil operation Abu Dhabi based company selected a Near Infra Red (NIR) water cut meter for a field trial to evaluate its capabilities of measuring the full range of water cut (0-100%) under transient flow conditions. The evaluation program was conceived to compare the real-time measurement from the NIR water cut meter with concurrent manual sampling drawn for different wells. 24 hours test were run on 12 wells and a total of 48 samples were collected.

Throughout the entire duration of the project, the NIR water cut meter was used along with a turbine flow meter and a Net Oil Computer (NOC). The NOC performed timed well tests integrating flow rate along with instantaneous water cut reporting, Net Oil and Net Water.

The NIR water cut meter was installed in the liquid leg of a converted three-to-two phase separator operating under transient flow conditions (batch mode), as there were constant changes in flow rates and separator liquid level. It was determined that this condition made the water cut downstream of the separator unstable being a challenge to synchronize the manual samples result with the NIR water cut meter readings.

Based on the success criteria, the NIR water cut meter evaluation was qualified as successful. The instrument proved to be within +/− 2% range of accuracy on water cut percentage measurement with a confidence level of 88%.

And since true water production from a producing well, in many cases, cannot be determined by a single sample as wells tend to produce varying levels of water during the course of the day. The combination of NIR water cut meter with NOC proved to be a much more accurate instrumentation system for well production determination.

This paper presents data obtained from multiple test stages. The well tests spanned the full range of water cut (0-100 %) on flow with transient conditions. The results showed successful water cut measurement uncertainty with dump cycle flow.
Extending Life of Fixed Offshore Installations by Integrity Management: A Structural Overview
Authors: Nabavian M. , Morshed A.
Published: February 2011

There are more than 6,700 platforms in operation worldwide and 30% of them have been in operation for more than 20 years. Many of these platforms are operating beyond their original design life. As more oil and gas discoveries have been made operators have been required to extend the life of their offshore assets without compromising personnel safety or the integrity, reliability and productivity of these assets.

Demonstration of structural integrity of mature assets particularly those reaching or exceeding their design life is of paramount importance when considering life extension. The risks that are commonly posed by life extension are: Corrosion - harsh corrosive environmentsOverload - wave action, additional topside and environmental loadsOperational changes - platform modificationsIncidents – ship collision, explosionFatigue

Managing the structural integrity of offshore assets is one of the most challenging tasks imposed by a life extension project. This includes industry wide consultations, to deploy new technologies such as online monitoring systems. Life extension of an offshore installation is necessitated for a variety of reasons and results in some possible changes. Changes to a platform require re-assessment of the structure to evaluate increase in environmental loading and fatigue damage on the substructure as well as to account for variation in topsides weight.
Unlocking the Shale Mystery: How Lateral Measurements and Well Placement Impact Completions and Resultant Production
Authors: Baihly J. D. , Malpani R. , Edwards C. , Han S. Y. , Kok J. C. , Tollefsen E. M. , Wheeler C. W.
Published: February 2011

Across many shale plays in North America, operators ask why production performance disparities exist among horizontal wells. For example, even though drilling and completion practices of a neighboring operator may be mimicked, significantly different production results are frequently observed. Several hypotheses have been presented on the subject with little consensus. In most of these wells, formation evaluation in the lateral section is limited to gamma ray. Using a single curve to model the structure leads to multiple solutions with no way to determine which one is correct. Accordingly, large uncertainties may exist in: 1) determining the relative geologic position of the wellbore, 2) placing perforation clusters, and 3) selecting the appropriate staging design and stimulation treatment for the resulting well placement.

To produce wells that perform to their maximum potential, it is fundamentally necessary to understand both the placement of the lateral in the reservoir and the placement of the perforations in the lateral. To optimize these placements, some measurements must be taken in the lateral. Obviously, the value of understanding where to locate the lateral and the perforations must be greater than both the direct costs associated with taking these measurements and the risk weighted costs associated with deploying tools in the lateral. A way to acquire this information while mitigating many of the aforementioned concerns is logging while drilling (LWD). Some of the measurements that LWD can capture along shale laterals include borehole/azimuthal images, stress, and mineralogy. With these comprehensive LWD measurements, not only can the captured data be taken for future completion design and analysis, they can also be used while drilling the lateral to steer the wellbore towards a desired target more accurately than gamma ray only.

This paper focuses on how lateral LWD measurements impact well placement, perforation selection, hydraulic fracture stage spacing, completion design, resultant production, and subsequent economics of horizontal shale wells. Practical LWD examples from the Eagle Ford and Woodford Shale plays are presented, along with their impact on the aforementioned subjects.

In this paper principles of using LWD measurements and interpretation in a field development plan are described, including relating LWD data to additional functions such as completion design, microseismic hydraulic fracture monitoring, production monitoring, and production logging. Ideas on how to optimize the amount and type of LWD measurements are proposed. Lastly, the paper will examine the impact of LWD measurements on the overall economics of horizontal shale wells.