bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful First Multistage Hydrajet Assisted Fracturing Process in an Ecuadorian Mature Field
Authors: Carrión Johana , Herrera Mauricio , Chuc Edgar A. , Chapa Jaime , Hernández Rubys 
Published: April 2016

Abstract
This case history paper presents the first multistage fracture stimulation of a mature field well in Ecuador using a hydraulic workover unit deploying jointed pipe. The process used a hydrajet perforating application followed by tubing-path pumping of the fracturing treatments.
To place fractures properly in each pay zone, effective diversion is required. This has been a challenge in many fields of Ecuador. Furthermore, multistage fracturing completions have represented a complex process when applying conventional methods because of the number of operations involved, such as perforating, fracturing, setting isolation plugs, and cleaning out the wellbore for each interval. Several trips into the well are often required, which adds time and costs to the entire completion intervention.
Because of the absence of some information as well as the presence of upper open perforated intervals, the hydrajet assisted fracturing (HJAF) process, which uses highly effective abrasive jet perforating immediately before the fracturing stage, was used to provide a degree of flexibility for making additional decisions and performing changes during the operation. This paper presents the detailed workover planning, multiple customized fracturing designs, operations data, and the stimulation results of the case study. The multistage hydraulic fracturing technique was designed and applied to individually fracture stimulate three formation layers in the Ecuador mature field. The method allowed using customized treatments for each zone and more aggressive fracturing schedules to promote high fracture conductivity or length when necessary.
Successful production from the mature Ecuadorian field was achieved using the multistage hydraulic fracturing HJAF method. Additionally, this method does not require mechanical zonal isolation between stages. The HJAF technique provides an attractive option for applications in similar wells to help recover additional reserves.
Using Sacrificial Agents to Enhance Surfactant Performance in the Eagle Ford Shale
Authors: He Kai , Yue Zhiwei , Xu Liang 
Published: April 2016

Abstract
Analysis of flowback and produced waters for surfactant residues showed that a majority of surfactants were retained inside the reservoirs (Rane and Xu 2015). While it is beneficial that surfactant typically does not flow back and continues to contribute to production increase, it is uncertain where in the reservoir the surfactant is actually retained or distributed. A plausible mechanism is that most surfactant may plate out prematurely on the formation rock in the near-wellbore (NWB) region, potentially restricting surfactant travel deeper into the reservoir. This paper discusses the study of a solution using a sacrificial agent (SA) to adsorb onto the formation surface which enables surfactants to further penetrate the Eagle Ford (EF) formation during a hydraulic fracturing treatment.
Laboratory testing revealed that injection of 1 gal/1,000 gal surfactant in the presence of 1 gal/1,000 gal SA enabled minimum adsorption of the surfactant on both proppant and formation rocks. Notably, the addition of SAs resulted in lower interfacial tension between fluids and enhanced hydrocarbon solubility. As a result, oil recovery was enhanced considerably. Additionally, approximately 70% friction reduction of the fracturing fluid with surfactant and SA was achieved and fluid stability and compatibility with standard guar-based fracturing fluids was also verified, thus providing compelling evidence for field trials.
Real-Time Integrated Subsurface Analysis to Determine Commerciality of the Pegasus West Exploration Discovery
Authors: Walters S. , Colbeck A. , Godhrawala H. , Trythall R. , Turner V. 
Published: April 2016

Abstract
The Pegasus West (43/13b-7) exploration well was drilled in Q3 2014 with the aim of testing gas presence and quality within the Carboniferous of the Southern North Sea. The overall objective was to assess whether the well was to be suspended for development, saving considerable point forward capex spend. Key to this decision was determining effective gas-in place (GIIP), as bulk GIIP estimations are not a reliable basis for development.
A workflow was put in place before spud with decision points and outcomes outlined, these included: 1) Decision to run core over two prognosed high reservoir quality sandstone intervals. 2) Selection of a wireline programme to deliver critical data over minimal runs. 3) Decision to well test (DST) based upon vertical and horizontal permeability calculations from core and wireline data. 4) Suspend or plugged and abandoned decision through assessment of minimum connected volume (MCV), effective GIIP, and minimum economic field (MEFS) size via DST analysis of individual sandstones.
A balance of minimising well cost without jeopardising the objectives and safety of the project was paramount. Operations were carried out efficiently through conducting static model, petrophysical, DST and economic analysis in-house. New working practices and tools were used within the data acquisition programme to give new insight into reservoir characterisation. A communication plan was established between onshore, offshore, subsurface, drilling, and service companies so all operated smoothly through decision criteria.
Through adopting the workflow the well was drilled within original authorised for expenditure time and budget. All decision points were made successfully, including recovering two cores over the highest quality sandstones, running wireline operations without delays and performing three isolated DSTs with a combined flow rate of more than 90MMscf/d. The MCV gave a low case effective GIIP of 53.4 BScf, which exceeded the MEFS of 40BScf; therefore the well was suspended.
An Innovative Approach for RPM Gel Water Shut-Off Simulation
Authors: Sheshdeh Milad Jokari , Awemo Kilian Nchungong , Yadav Atul 
Published: April 2016

Abstract
Since the potential of relative permeability modifying (RPM) gels for water shut-off was discovered, many researchers focused on understanding the mechanisms by which, these gels perform their disproportionate permeability reduction (DPR) behavior. The focus on this concept and developments in experimental methods and laboratory equipments, have led to clearer and reasonable explanations for the mentioned behavior of these gels. However, the focus on the experimental scope of these gels has resulted in lack of studies on the numerical simulation of the RPM gels injection in the reservoir.
In this paper, it is tried to use the achieved experimental knowledge by the mentioned experiments, to analyze the feasibility of the current approaches and to come up with a new approach.
Polymer option of commercial black oil simulators is the first approach analyzed and it is proved that using this approach results in false prediction of the relative permeabilities in the treated cells after gel adsorption. The reason is the assumption of the simulators about the effect of the polymer adsorption on oil relative permeability reduction.
An alternative to polymer option is defining the gels as solid particles and interpolating the relative permeabilities between the initial and treated sets as a function of the defined solid particles adsorption to the rock surface. Since solid particles cannot be present in the injecting stream, they have to be defined as liquid particles and turned to solid phase in the reservoir via the reactions. Defining reactions necessitates having the simulation in compositional model which is sometimes not favorable due to larger run times and required PVT data for fluid modeling for a compositional run.
Surfactant option has the interpolation capability too and it is run in black oil model. In other words it has the capabilities of the compositional approach, but due to its black oil formulation, run times are shorter and no fluid modeling is required. However, using surfactant option of a simulator, changes the capillary pressure and results in reductions in interfacial tension between oil and water. These EOR effects of surfactant presence in the reservoir has to limited by manipulating the defined functions. The approach is then validated against a single well treatment observed data and could reproduce the observed production rates in the 18 months period after the treatment. Validation of the approach permits us for using this approach to simulate RPM treatments in different scales.
The Komsomolskoye Field - Fast Track Development of a Remote Oilfield Using a Blend of Horizontal and Vertical Wells
Authors: Lechner Michael , Uspanov Marat , Ilchibayeva Aigul 
Published: April 2016

Abstract
This paper tells the success story of the Komsomolskoye field which was brought on stream in 2008, some 24 years after its discovery in 1984. Ramp up of oil production to peak of some 7,000 bopd was achieved within only five years. The field is located in a remote location of Western Kazakhstan - onshore on the Buzachi Peninsula, some 350 km from the regional city of Aktau and 110 km from the nearest village Kyzan. Road access from Kyzan is available only through a gravel road.
The subsurface field development since 2008 consists of five horizontal oil producers, five vertical water injectors and two vertical gas injectors. The horizontal producers contribute the bulk of the field's oil production and were drilled from two well pads due to the semi-offshore nature of the Komsomolskoye field - seasonal flooding restricts access to a large portion of the surface area during half of the year. Produced gas and produced water are re-injected at the periphery of the field for pressure support, in addition to a weak aquifer support. Moreover, additional injection water is sourced from two dedicated shallow water wells and likewise injected into the reservoir. In addition to the five major horizontal producers, there is a pre-2008 well stock of ten vertical producers, which were successfully re-entered and of which eight were brought online to date.
The favourable areal layout of the composite vertical/horizontal pattern plus the improved/enhanced oil recovery effects of water injection and miscible gas injection, respectively are key factors which enabled the following achievements: fast track ramp up of oil production rate to some 7,000 bopd within only five yearszero gas flaring, due to gas re-injection and own consumption for power generationreservoir pressure throughout the field being safely above bubble point pressurea current recovery factor of 12% as of July 2015a projected recovery factor by year 2039 of 36% for a development scenario with no additional wellsa projected recovery factor by year 2039 of some 45% for a development scenario with 5 additional vertical producers
As a case study, this paper illustrates a recent "fit for purpose" development project and may serve as an example for sustainable oilfield development in remote locations. It could be of benefit to organizations and individuals who are involved in the operation of comparable assets.
Unlocking the Potential of Remaining Hydrocarbons Using Time Lapse Pulsed Neutron Capture Logs in Complex Completions - A Case Study from UK Central North Sea
Authors: Ali Arfan , Small Simon , Singh Kamaljeet , Martin Andy 
Published: April 2016

Abstract
Reservoir surveillance using pulsed neutron capture (PNC) sigma data has shown its importance historically (Madhavan et al. 2015; Odom et al. 1994; Gournay and Maute 1982). This paper proposes to discuss the planning, acquisition and analysis of the PNC sigma data in complex well completions with multiple casing strings and hole sizes. A case study from the Gannet A field located in the Central North Sea of the United Kingdom has been presented to demonstrate the importance of having the correct logging environment and its subsequent effect on the PNC sigma processing and interpretation. The consequence of not making such detailed checks may result in mis-interpretation of the sigma data leading to incorrect conclusions about fluid dynamics, and risky decisions in water shut-off (WSO) opportunities and additional perforations. The integration of PNC sigma data with other surveillance techniques such as production logs and 4D seismic has also been discussed to understand the reservoir dynamics for Well Reservoir and Facility Management (WRFM) planning purposes.
The Gannet A field comprises an Eocene age deep marine amalgamated turbidite sand reservoir with combined dip/stratigraphic closure. The field initially had a gas cap and a thin oil rim. In the early 1990’s, eleven horizontal producer wells were drilled to produce solely from the oil rim. Two additional wells were used to re-inject a portion of the produced solution gas into the gas cap. Gas injection ceased in 2001 due to unexpected strong aquifer ingress from the North-East. The oil rim and aquifer moved upwards into the former gas cap in the North resulting in a tilted contact from the North to the South and watering out of the producers progressively over time. The PNC sigma data has played an important role in accessing the migrated oil rim and understanding reservoir movement. In 2015, PNC sigma data helped to add perforations in three wells in the Gannet A field adding approximately 5,000 bbl/d of incremental oil.
This paper focuses on the three key areas in PNC sigma interpretation which are often overlooked. Firstly, quantifying the effect of the type of annuli fill, hole size, and multiple casing/tubing strings on computed saturations; secondly, the importance of using consistent environmental parameters for time lapse comparison of the PNC sigma data; and thirdly, the added uncertainties in computed saturations due to the presence of three fluid phases; i.e. migration of oil rim into the original gas cap and its subsequent sweep with water.
Investing in Technology for More Information - When is it Worth it?
Authors: Wilson Séadhna 
Published: April 2016

Abstract
At any stage of the Exploration and Production cycle decisions must be made with limited information. This situation can always be improved by investing more money or time in improving the quality and variety of information available. However, this in itself presents a decision as to whether the investment to get new information such as a new seismic survey is worth it. This paper outlines a practical and structured method to estimate the value of new information in monetary terms, which can be used to make an informed business decision on whether the new information is worth it.
The method is comprised of two primary elements. Firstly the problem is defined using a decision tree analysis approach that considers what decisions are to be made and their possible outcomes. Secondly, a collaborative workshop is used to estimate the probabilities required to populate the decision tree. This then enables the Expected Monetary Value to be calculated both with and without the technology that acquires the new information. The difference between the two is approximated as the value of the information. This paper uses a case study approach to explain this method that considers an operators dilemma in deciding whether or not to drill an appraisal well.
Obtaining a meaningful result from this process requires time and commitment from management and technical staff. However, at stake are the considerable sums of money in acquiring the new information and the subsequent investment decisions that draw on the new information. The method described as a minimum provides fiscal information to make investment decisions and at best, provides a framework in which the benefits and risks of investing in new technology can be fully understood.
There has already been much published on the use of decision trees to estimate the value of information. However, in practice it can be difficult to estimate the probabilities required for a decision tree analysis to work as they are not intuitive to describing the situation. This approach simplifies this by arranging the mathematics to make the task of the workshops clearer and more achievable. The result is a practical method that can be easily understood and implemented.
Differential Responses to Preemergence and Postemergence Atrazine in Two Atrazine‐Resistant Waterhemp Populations
Authors: Ma Rong , Evans Anton F. , Riechers Dean E. 
Published: April 2016

Waterhemp [Amaranthus tuberculatus (Moq) Sauer] is a difficult‐to‐control dicot weed in the United States. Atrazine [6‐chloro‐N‐ethyl‐N’‐(1‐methylethyl)‐1,3,5‐triazine‐2,4‐diamine] is commonly used for preemergence (PRE) and postemergence (POST) waterhemp control in maize (Zea mays L.). Previous research reported that atrazine metabolism via glutathione S‐transferase (GST) activity contributes to atrazine POST resistance in two waterhemp populations from Illinois, designated MCR (McLean County, Illinois, resistant) and ACR (Adams County, Illinois, resistant). Objectives were to quantify responses of these populations to atrazine PRE and determine if the combination of a GST inhibitor and atrazine PRE or POST increases their control. Dose‐response analyses indicated MCR was resistant to atrazine PRE relative to ACR or WCS (Wayne County sensitive; herbicide‐sensitive population), despite MCR and ACR exhibiting equivalent levels of atrazine resistance POST. The ACR response to atrazine PRE (LD50) was intermediate compared with MCR and WCS. Seedling survival of ACR was reduced by 4‐chloro‐7‐nitrobenzofurazan (NDB‐Cl; a GST inhibitor) and atrazine PRE more than atrazine PRE alone, but not in MCR. Atrazine following NBD‐Cl applied POST inhibited seedling growth in ACR, but not in MCR. Enhanced atrazine activity with NBD‐Cl further supports rapid metabolism via GSTs as the main atrazine‐resistance mechanism in ACR. GST(s) that metabolize atrazine in MCR may not have been completely inhibited by NBD‐Cl, indicating that similar yet distinct atrazine‐resistance mechanisms exist in MCR compared to ACR. In conclusion, atrazine PRE (with or without NBD‐Cl) still controls ACR when applied at typical field‐use rates in maize, but the length of residual activity may be shorter than in sensitive populations.Core Ideas

Two waterhemp populations are resistant to atrazine POST due to increased metabolism by GST enzymes.
Since atrazine can also be soil applied, quantifying the levels of resistance in these populations is important for weed management in maize.
The MCR population was resistant to atrazine PRE and displayed a higher level of resistance to atrazine PRE than the ACR population.
NBD‐Cl, a metabolic inhibitor of GST enzymes, enhanced atrazine activity in the ACR population but not MCR.
The length of residual activity of atrazine may be shorter for controlling these populations in maize compared with sensitive populations.
Ammonia Emission from a Beef Cattle Feedlot and Its Local Dry Deposition and Re‐Emission
Authors: McGinn S. M. , Janzen H. H. , Coates T. W. , Beauchemin K. A. , Flesch T. K. 
Published: April 2016

Ammonia (NH3) volatized from livestock manure is affiliated with ecosystem and human health concerns and decreased fertilizer value of manure and can also be an indirect source of greenhouse gas. Beef cattle feedlots, where thousands of cattle are grouped together to enable greater control of feed management and production, are hot spots in the agricultural landscape for NH3 emissions. Quantifying the feedlot NH3 emissions is a difficult task, partly due to the reactive nature of NH3 within and surrounding the feedlot. Our study used a dispersion model coupled to field measurements to derive NH3 emissions from a feedlot in southern Alberta, Canada. The average feedlot NH3 emission was 50 μg m−2 s−1 (85 g animal−1 d−1), which coincides with a low dietary crude protein content. At a location 165 m east of the feedlot, a flux gradient (FG) technique measured an average NH3 deposition of 12.0 μg m−2 s−1 (west wind) and 5.3 μg m−2 s−1 (east wind). Ammonia FG emission averaged 1 μg m−2 s−1 with east winds, whereas no NH3 emission was found for west wind. Using soil‐captured NH3, there was a decrease in deposition with distance from the feedlot (50% over 200 m). Collectively, the results of this study provide insight into the dynamics of NH3 in the agricultural landscape and illustrate the need for NH3 mitigation to improve the environmental and economic sustainability of cattle feedlots.Core Ideas
Beef feedlots are “hot spots” of ammonia emissions in the landscape.
A significant fraction of the emitted ammonia is deposited to local land.
Nitrogen fate of emitted ammonia is dynamic.
Mineralogical Transformations and Soil Development in Shale across a Latitudinal Climosequence
Authors: Dere Ashlee L. , White Timothy S. , April Richard H. , Brantley Susan L. 
Published: April 2016

Core Ideas
Detailed characterization of the morphology, geochemistry, and mineralogy of shale‐derived soils across a climosequence documents enhanced weathering and soil development with increasingly warm and wet climates.
The deepest weathering reaction observed in the regolith across the shale climosequence was plagioclase feldspar dissolution, which may be the profile initiating reaction that begins the transformation of shale bedrock to weathered regolith.
The abundance of chlorite and its transformation to vermiculite and HIV are more likely controlling regolith thickness in these soils.
To investigate factors controlling soil formation, we established a climosequence as part of the Susquehanna‐Shale Hills Critical Zone Observatory (SSHCZO) in central Pennsylvania, USA. Sites were located on organic matter‐poor, iron‐rich Silurian‐aged shale in Wales, Pennsylvania, Virginia, Tennessee, Alabama, and Puerto Rico, although this last site is underlain by a younger shale. Across the climosequence, mean annual temperature (MAT) increases from 7 to 24°C and mean annual precipitation (MAP) ranges from 100 to 250 cm. Variations in soil characteristics along the climosequence, including depth, morphology, particle‐size distribution, geochemistry, and bulk and clay mineralogy, were characterized to investigate the role of climate in controlling mineral transformations and soil formation. Overall, soil horizonation, depth, clay content, and chemical depletion increase with increasing temperature and precipitation, consistent with enhanced soil development and weathering processes in warmer and wetter locations. Secondary minerals are present at higher concentrations at the warmest sites of the climosequence; kaolinite increases from <5% at northern sites in Wales and Pennsylvania to 30% in Puerto Rico. The deepest observed weathering reaction is plagioclase feldspar dissolution followed by the transformation of chlorite and illite to vermiculite and hydroxy‐interlayered vermiculite. Plagioclase, although constituting <12% of the initial shale mineralogy, may be the profile initiating reaction that begins shale bedrock transformation to weathered regolith. Weathering of the more abundant chlorite and illite minerals (∼70% of initial mineralogy), however, are more likely controlling regolith thickness. Climate appears to play a central role in driving soil formation and mineral weathering reactions across the climosequence.