bluuebunny/crossref_metadata_2025_split huggingface dataset:
OML58- Upgrade: Rejuvenating a 40 year old oilfield onshore Nigeria through Heavy Simultaneous Production and Construction Operations.
Authors: Saintpère Stéphane , Ologe Jacob S , Perrono Fabrice , Ikpa Henry , Udodong John Edet , Lys Jean-Yves 
Published: October 2012

Abstract
It is a unique situation amongst the fields operated by Total that has recently taken place on the OML58 Oil and Gas facilities located in the Niger Delta area of Nigeria. Major financial investments over 4 years, and more than 4000 workers at peak on the different locations of the field, for a total of more than 20 millions worked hours, were necessary to complete the first phase of the transformation of an oil producing site into a gas producing site. Eventually, the field will have its life extended for another 30 years, but if it is mainly oil that has been produced so far, 80 % of the future production will be gas.
These few figures illustrate what is at stake in a region where Total has been operating for over 45 years and has confidence to go further and bring the installations to their full production capacity. Right from the beginning, it was decided that Simultaneous Production and Construction Operations (SIMOPS) would be the mode of operations. Large scale SIMOPS on remote existing aging facilities, spreading over years, is definitely not a usual challenge. It is even more difficult when it takes place on running installations where gas under high pressure circulates almost everywhere. Therefore, a dedicated organization allowing a strict control of the SIMOPS was implemented. The paper will describe the advantages of a transversal approach where production operations teams and construction teams are aligned on common shared objectives. It will also show how a challenging operating approach in a difficult context (unknown underground conditions, aging facility challenges, etc) can lead to a significant reduction of production short-falls without compromising safety. Furthermore, the case will also highlight how such a big project can positively impact the development of local communities and participate to their sustainable development.
Reducing Uncertainties in Casing Depth and Formation Evaluation Using Look-Ahead Logging While Drilling Technology
Authors: Deri C. Peter , Peternell Ana , Hebert John , Fisher James L. , Gibbs Rudy B. , Cornell Robert , Moreno Javier 
Published: October 2012

Abstract
Logging while drilling (LWD) technology has been used successfully to overcome the drilling challenges when exploring a caprock hostile environment in the Main Pass area of the Louisiana Gulf Coast. Because of the geological setting, special steps needed to be taken to mitigate the obstacles and uncertainties while drilling. Successful acquisition and application of selected measurements led to achieving the drilling and formation evaluation objectives.
To drill the optimal wellbore, seismic-while-drilling technology was employed to optimize casing depths and minimize drilling risks such as mud losses and potential H2S. Additional techniques were used to help make the decision to set casing and maintain a viable wellbore for logging and completing the well.
For the second challenge, providing formation evaluation without compromising drilling safety and data quality, additional LWD services were applied. A resistivity-at-the-bit laterolog imager and a multifunction formation evaluation platform were employed to satisfy both the drilling demands and the formation evaluation needs. Having drilling mechanics and formation evaluation measurements available provided not only advanced measurements closer to the bit, giving a better chance of reducing invasion effects, but also impacted the drilling time through shorter rathole section. In addition, the laterolog resistivity imaging provided dips and texture information to map the structure and identify different geological features. Using these technologies, 100 ft were drilled into the caprock with enough information to evaluate the economical value of the prospect reservoir. The combination of these technologies and the ability to interpret the data streamed while drilling allowed the operator to successfully set casing at the top of the limestone caprock. In the end, the drilling risks and uncertainties experienced in the past were totally eliminated by the proper use of LWD technology.
Best Practices for Using Flares to Meet Proposed EPA Emissions Regulations for Hydraulically Fractured Natural Gas or Oil Wells
Authors: Reed Scott D. 
Published: October 2012

Abstract
The new 2012 EPA Oil and Natural Gas Air pollution standards, enacted April 17, 2012, are designed to reduce harmful emissions of VOCs from hydraulically fractured wells. VOCs in the presence of sunlight promote the formation of smog (grade-level ozone) near areas where oil and gas production occurs. The four-targeted areas of VOC reduction in oil and gas production will affect some 25,000 wells per year as well as storage tanks and other processing equipment. Flare systems are proposed as one of the preferred control devices to meet these new regulations.
Complicating the hydraulic fracturing production picture further, the industry expects new EPA flare regulations to be proposed shortly. These regulations are currently under review with public comment underway via the TCEQ and EPA Flare Stakeholder Task Force.
This paper will address specifics of both new regulations and provide guidance for cost-efficient and effective flare system designs.
Optimizing Water Injection Rates for a Water-flooding field
Authors: Liu Feilong , Guthrie Charlie , Shipley David 
Published: October 2012

Abstract
Setting proper water injection rates for the injection wells is a key factor to successfully operate an oil field under water flooding. The success of such activity could (a) reduce water cycling at field, section and pattern levels; (b) improve water/oil ratio (WOR) and areal sweep efficiency; (c) improve oil production and recovery by directing water injection to specific zones and areas; and (d) reduce OPEX by improving water utilization.
Typically, the onsite engineers adjust injection rates using heuristics. While this does improve performance we feel that a more systematic approach can be developed which will lead to further gains. In this paper, we present a systematic method, using the linear programming, to optimize the water injection target rates.
In this method, the reservoir is considered to be a system which can be modeled as a collection of continuous-time impulse responses that convert injection rates into a production rate. A very simple two parameter parametric model, like diffusivity-filter, has been used to quantify the injector-producer continuous-time impulse responses channel model and the Extended Kalman Filter has been used to establish the allocation factors between injectors and producers in the water-flooded field. Subject to constraints, including the total available water amount, the maximum and minimum injection rates, the maximum total production fluid for a producer and a gauge setting, a linear programming optimizer has been applied to determine the optimized water injection rate, based on the established allocation factors.
This method was pilot tested on a Chevron oilfield for 3 months. The decline curve for 6 months and for 2 months of historical oil production data have been calculated. The 3 month pilot test result indicated that the optimized oil production matches the historical 6-month decline curve very well with about 22% less total daily water injection. Also we saw about 2% incremental production above the historical 2- month decline curve (again with about 22% less total daily water injection). These results suggest that this systematic method may provide a way to optimize the water injection target rates.
Getting Ahead of the Regulators by Building Your Own Emissions Profile
Authors: Stuver Susan , Alonzo Jesse , Holditch Stephen , Mills Skip 
Published: October 2012

abstract

Research Objective
Development of improved air emissions management through better emissions estimation methodologies and best available estimation techniques for hydraulic fracturing phases.

Problem Statement - Policy without data
Federal and State regulators are developing air emissions regulations that will have an impact on the oil and gas industry. In the near future, regulatory requirements will be put in place that entail the measurement and reporting of such air emissions as NOx, VOCs, Greenhouse gases (such as methane), NO2, SO2 and more.1 Historically, air emissions studies have been conducted using methods that sample off site, ambient air. Much of the data gathered in this fashion falls short because this collection method fails to consider emissions transport from other industry such as power generation, waste water treatment, or even emissions that blow in from other countries. It also falls short of being helpful to the industry since the operators and service providers are left questioning which pieces of equipment are producing these emissions if any.

Solution
If properly characterized, these sources may be eliminated from regulatory compliance requirements by simply identifying and demonstrating their minimal contributions as de minimis sources. The research team traveled to a hydraulic fracturing site on the Eagle Ford Shale Play and collected real time activity data from equipment that has the potential to release large amounts of air pollutants. Actual run times and load factors of the engines were measured. The activity data was then compared to data collected in the traditional manner of conservative off-site emission assumptions. Regulators performing offsite estimates will typically default to the conservative assumption that engines are operating at 100% load and 24 hours a day, and every day that the operation occurs.
The Core Analysis Elephant in the Formation Evaluation Room
Authors: McPhee Colin 
Published: October 2012

Abstract
Core analysis provides the only direct and quantitative measurement of reservoir petrophysical properties and should provide the ground truth for integrated formation evaluation. However variable data quality, the sensitivity of results to different test methods, poor reporting standards, and the reluctance of some vendors to share experience and expertise have all contributed to basic mistakes and poor data quality. It is easy to blame the vendors, but in too many cases, an inconsistent or inappropriate approach to the design, management and interpretation of the core analysis programme has been adopted and exacerbated by the conflicting requests of the end users. In combination, this has led to a situation where around 70% of legacy SCAL data are not fit for purpose.
We present a core analysis management road map which is designed to increase the value from core analysis investments by enabling a more pro-active, more coherent and more consistent approach to programme design and data acquisition. Firstly, this involves reviewing legacy data and understanding the impact of rarely-reported experimental artifacts on fundamental rock property measurements. Can data be corrected or re-interpreted or are new tests required? Secondly, a multi-disciplinary core analysis management strategy is described. This is designed to encourage more effective engagement between stakeholders and the data acquisition laboratory through improved test and reporting specifications, pro-active test programme management, and real time quality control.
Acoustic Induced Vibration (AIV) Case Study for WDDM Onshore Facilities
Authors: Moussa Atef Mahmoud 
Published: October 2012

Abstract
In gas applications with high-pressure drops and/or high-velocity gas flow, Acoustic Induced Vibration (AIV) occurs when very high sound levels are propagated in piping. If the sound levels are high enough, they will excite the circumferential vibration modes of the pipe. This allows the pipe to vibrate in and out as the sound wave moves through the piping. Most often this occurs downstream of pressure-reducing valves or safety-relief valves PSV‘s but AIV can occur at any location where the pressure drop or mass flow rate is sufficiently large. The level of pipe wall vibration is so high that it can induce fatigue cracking of the pipe and potentially cause catastrophic pipe failure. West Delta Deep Marine (WDDM) onshore of the slug catcher M9001 had a recent failure in the flare header as result of accumulating AIV effect. As a consequence of this failure Enppi/Burullus & Foster Wheeler undertaken an engineering assessment study to investigate the risk of AIV (Acoustic Inducted Vibration) for hall the plant & find out the corrective & engineering solution to protect the plant from any failure could be occurred as resulting of AIV affect.
Eagle Ford Shale - An Early Look at Ultimate Recovery
Authors: Swindell Gary S. 
Published: October 2012

Abstract
Although the Eagle Ford shale is early in its history, the study provides a comprehensive examination of per well recovery and decline data in the South Texas trend using the latest production information up to early 2012.
Individual forecasts of the estimated ultimate recovery (EUR) were made for more than 1,000 horizontal wells in the South Texas Eagle Ford shale trend and statistics were developed for EUR in the 10 primary counties where development is occurring. The study used rate vs. time plots and included all the producing wells in the trend which have decline data believed to be sufficient to project EUR. Normalized decline curves were developed for each county and distributions of EUR were produced. In addition, for a portion of the wells, correlations were made between EUR, frac size, horizontal length and the date of first production.
The results show that for the 10 county trend, the average and median EUR per well were 206,779 barrels of oil equivalent (BOE) and 160,519 BOE, respectively. Of the counties with more than 50 wells, the best are DeWitt (403,715 BOE) and Karnes (210,801 BOE). Live Oak, with only 28 wells averages 248,818 BOE. The normalized rate vs. time plots show minor hyperbolic behavior. In fact, for all the wells in the study, the normalized oil decline was 76% and the gas 60%, with hyperbolic exponents of .25 and .40, respectively. The wells have clearly become better since the start of horizontal drilling, but the average performance has not shown much improvement since mid-2010 even as the frac sizes became larger. The best well performance has generally come from wells with horizontal legs in the 4,000 to 5,500 ft. range.
The South Texas Eagle Ford shale trend is one of the most active in the US, adding approximately 100 new producing leases each month. Although a great deal is being written about the trend, there is a lack of independent, hard data on per well reserves. This study provides an early look at individual well ultimate recovery.
Field Application of Polymer Microspheres Flooding: A Pilot Test in Offshore Heavy Oil Reservoir
Authors: Liu Chao , Liao Xinwu , Zhang Yunlai , Chang Ming-Ming , Mu Chunrong , Li Tingli , Qin Runsen , Fu Rong , Bie Xvwei , Zheng Jianjun 
Published: October 2012

Abstract
Chemical injection has been used to combat reservoir sweeping and water-control problems in the last two decades with different degrees of success. Many of the methods face the challenges of chemical durability, penetration depth, rock-fluid compatibility, and economical justification. Polymer microsphere injection is a new method developed recently to address these challenges in controlling waterflood conformance to enhance recovery efficiency. Made by emulsion synthetic technique the polymer microsphere expands at contact with reservoir water resulting in plugging of high permeability pore throat deep into the formation to divert the water flow path. The laboratory experiments showed an improvement of recovery factor by 14 to 16%. This paper presents the first field test in an offshore environment of a heavy oil reservoir Q in Bohai Bay in China.
Q oilfield is a heterogeneous heavy oil reservoir suffering from fast water breakthrough with poor recovery. The polymer microsphere was injected into an eleven-well pilot. The injection pressure increased following injection of microsphere solution. Multiple fall-off tests were performed to monitor the plugging of flow channels at different times. The time taken to reach the reservoir pressure in the fall-off test increased with flooding time for four months demonstrating an effective channel plugging. Most of surrounding producers showed responses to microsphere injection in both pressure and oil production. The incremental recovery benefit to the test cost is estimated to be 4:1 to 6:1.
The encouraging pilot test demonstrated the potential of polymer microsphere flooding to combat reservoir conformance challenge. This test needed simple equipments which were easy to be operated in the offshore platform environment. Further polymer microsphere flooding tests are in plan in China Bohai Bay area.
The Wafra Field First Eocene Carbonate Reservoir Steamflood Pilots: Geology, Heterogeneity, Steam/Rock Interaction, and Reservoir Response
Authors: Meddaugh W. Scott , Osterloh W. Terry , Gupta Ipsita , Champenoy Nicole , Rowan Dana , Toomey Niall , Aziz Shamsul , Hoadley Steve , Brown Joel , Al-Yami Falah 
Published: October 2012

Abstract
The Paleocene/Eocene First Eocene dolomite reservoir is a candidate for continuous steamflooding due to its large resource base and low estimated primary recovery. There are two steamflood pilot projects in operation to evaluate reservoir response to steam injection: a single pattern pilot (SST) and a 40-acre, 16 pattern pilot (LSP). At the SST an interval with abundant tidal flat cycle caps characterized by muddy, finely crystalline dolomites with low porosity and permeability may be the observed vertical barrier to steam migration. Detailed studies, including micropermeameter measurements and micro-CT scans were used to characterize the heterogeneity. Data suggest that similar vertical barriers may exist at the LSP. Early steamflooding results show a positive response to injection and multiple thermal events (likely baffles rather than barriers). The data also shows the occurrence and distribution of some lateral high permeability pathways between injectors and producers as well as between producers. While the rapid temperature response observed in a few wells may reflect fractures or karst-like zones, simulation using very fine grids shows that some wells will experience very short breakthrough times without fracture or karst-like zones.
Injection of high temperature, high pH fluids may induce fluid/rock interactions that affect reservoir fluid flow near-well and in-depth. This in turn could affect storage capacity, production and injectivity. Reactive transport models (2D-RTM) were run to simulate high pH steam injection into the First Eocene reservoir for a continuous injection period of 6-12 months to understand possible changes in mineralogy, coupled with porosity change and potential scaling. Initial results predict precipitation of calcite and brucite, dissolution of dolomite and anhydrite, and conversion of gypsum to anhydrite. Sensitivity studies examined the impact of steam quality, pH, rock surface area, reaction rates, and mineralogy.
Workflow to Evaluate Maximum Allowable Treating Pressures, Tubing Movement, and Tubular Limits for Deepwater Subsea and Dry-Tree Fracpacks
Authors: Strobel Marshal , Oubre Brennan , Holley Alan 
Published: October 2012

Abstract
Deepwater wells using fracpack stimulation are progressively moving to ultradeep water depths and total depths; the bottomhole pressures (BHPs) and temperatures of future reservoirs could exceed 20,000 psi and 250°F. To safely perform deepwater fracpack treatments, the following pressure and tubular limitations should be considered:
Maximum surface tubing pressure because of pipe limitations and gravel pack assembly component ratings. Maximum surface annulus pressure because of blowout preventer (BOP) ratings. Maximum allowable tubing movement while pumping to help prevent premature job cessation. Maximum allowable downhole slackoff and overpull because of well path, pipe, pipe connections, and downhole component ratings.
Depending on the well depth, pressure, temperatures, and BOP type (subsea or dry-tree), various pipe, connection, or equipment limitations might be exceeded during multistage fracpack stimulation operations. Initial pipe loading as well as pre-fracpack stages, such as the pickle, acid treatment, or minifrac calibration treatment, will alter the pipe failure and movement conditions and must be accounted for in the final completion design.
Because of these concerns, a workflow process has been delineated to evaluate the maximum allowable treating pressures, tubing movement, and tubular limits for deepwater subsea and dry-tree fracpacks across four components:
Input component to consolidate well and stimulation data for further workflow analysis. Surface treating pressure evaluation component to analyze certain treating pressure limitations. Commercial wellbore, casing, and tubing simulator to evaluate work string safety factors, tubing movement, and downhole forces. Commercial torque and drag simulator to evaluate surface slackoff requirements and allowable work string overpull.
A description of the variables, range of values, and other considerations for each of these four components is discussed, and the benefits of using this process to evaluate fracpack stimulation are shown. Well case histories are also used to support this process.
Field Application Results of Water Permeability Modifier in Fracture Stimulation Treatments in Western Siberia
Authors: Ladut'ko Alex , Goss Michael , Dalrymple E. Dwyann , Chang K. T. 
Published: October 2012

Abstract
Historically, hydraulic-fracture stimulation of zone zones with directly underlying waters has not been considered a practical method for improved oil recovery. This was because the stimulation treatment could result in water cuts from 90-100%.
Many of the oil and gas reservoirs in Western Siberia have production zones that fall into this scenario. The zones contain high-permeability streaks of mobile water and have water bearing layers above and/or below the producing zone. When a hydraulic-fracturing treatment is performed on such production zones, unintentional stimulation of the adjacent water bearing layers occurs. As a result, high water production is observed from the high permeability streaks of water or the adjacent water-bearing layers. Over a period of time, those wells will continue to lose hydrocarbon production rate, while the water cut continues to increase. Water separation and disposal of the produced water is expensive and not always successful.
Using recent water permeability modifier (WPM) chemistry advances, the hydraulic-fracture stimulation of such zones has now been shown to be an effective way to stimulate and produce the mature oil and gas fields such as those found in Western Siberia. The incorporation of a water permeability modifier with a hydrophobic backbone containing hydrophilic branches with the hydraulic fracture stimulation has proven to be very effective in obtaining oil production above what was anticipated based upon comparison with offset wells fracture stimulated without the WPM. It was further observed that not only was the produced water rate typically less than previously observed, but that it continues to decline over time instead of increasing.
This paper presents the results of the implementation and analysis of 11 WPM fracture-stimulation treatments that were performed in a field in Western Siberia in 2009. Discussed will be the WPM technology, treatment design, post production analysis, and recommendation selection of candidates and successful implementation of the WPM technology in the western Siberian fields.