bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.