bluuebunny/crossref_metadata_2025_split huggingface dataset:
Structure, Stoichiometry, and Modeling of Calcium Phosphonate Scale-Inhibitor Complexes for Application in Precipitation-Squeeze Processes
Authors: Shaw S.S.. S. , Sorbie K.S.. S. 
Published: March 2015

Summary
Phosphonate scale inhibitors (SIs) applied in downhole-squeeze applications may be retained in the near-well formation through adsorption and/or precipitation mechanisms. In this paper, we focus on the properties of precipitated calcium phosphonate complexes formed by nine common phosphonate species. The stoichiometry [calcium ion to phosphorous (Ca2+/P) ratios] in various precipitates is established experimentally, and the effect of solution pH on the molar ratio of Ca2+/P in the precipitate is investigated. All static precipitation tests were carried out in distilled water (DW), with only Ca2+ [as calcium chloride (CaCl2)] and SI present in the system at test temperatures from 20 to 95°C. The molar ratio of Ca2+/P in the solid precipitate was determined by assaying for Ca2+ and P in the supernatant liquid under each test condition by inductively coupled plasma (ICP) spectroscopy (Ca0 and P0 are known, but are also measured experimentally). We show experimentally that the molar ratio of precipitated Ca2+/P (or Ca2+/SI; or n in the SI–Can complex) depends on the SI itself and is a function of pH for all phosphonates tested. It is found that, as pH increases, the molar ratio of Ca2+/P (n in the SI–Can) in the precipitate increases up to a theoretical maximum, depending on the chemical structure of the phosphonate. Our findings corroborate proposed SI-metal complex-ion structures, which were presented previously in Shaw et al. (2012c), as discussed in detail in this paper. In addition, the precipitation behavior of the various compounds is modeled theoretically by developing and solving a set of simplified equilibrium equations. We find that the precipitation behavior can be modeled, but only if a fraction (β) of “non-SI” of the initial phosphonate SI is taken into account. The quantity β can be as high as 0.2 (i.e., approximately 20% non-SI), although there is a degree of variability in this factor from product to product. However, good quantitative agreement is shown comparing the predictions of the equilibrium-solubility model with the experiment. Such models can be used directly in the modeling of field phosphonate precipitation-squeeze treatments.
Persistence and a Creative Facility Solution Enable Successful Development of Stranded Offshore Gas
Authors: Coghlan G.. , Westera D.. , Ritzema K.. 
Published: March 2015

Summary
The F3-FA field is a small, offshore gas field in the Dutch sector of the southern North Sea. The discovery well drilled there in 1971 located rich gas in the Jurassic Scruff Greensand (SGSS) formation; however, its constrained size meant that field appraisal could not take place for another decade, with two wells drilled in 1982. Following appraisal, the field struggled to compete for investment capital and pipeline access against other development opportunities. Ultimately, the original operator exited the field in 2008, and Centrica Energy purchased its equity and field operatorship.
A different opportunity set allowed Centrica and its partner EBN to advance the field development. Uncertainty regarding the dynamic performance of the field and recognition of its limited volumes, and, therefore, limited producing field life, led to the adoption of a self-installing platform (SIP). The platform is currently the largest of its kind in the world at 133 m high, being slightly heavier than the Eiffel Tower and designed for future reuse at another location for the purpose of producing some other small accumulation.
The platform was installed in September 2010, with full processing and compression facilities in place, and tied into the northern offshore-gas-transport (NOGAT) pipeline system. Production is from a single, near-horizontal production well. The well design called for drilling across two fault blocks with potentially different fluid charges and pressures. The reliance on a single development well reflected the marginal nature of the development, with a range of reserves that reflected uncertainty about gas distribution and the dynamic behavior of a reservoir that did not have any analogs to draw on. First production was achieved in January 2011, and, to date, the field has performed strongly, with no indication of the aquifer influx that was an uncertainty going into development. The condensate yield has also proved to be much higher than anticipated.
The prolonged time between exploration and first production is a familiar trait for many small developments in recent years in the southern North Sea, often executed by a new breed of operator. This length of time is also typical of the choices needed to bring such fields to production, given modest reserves and unresolvable subsurface uncertainties.
Temperature-Prediction Model for a Horizontal Well With Multiple Fractures in a Shale Reservoir
Authors: Yoshida Nozomu , Zhu Ding , Hill A.D.. D. 
Published: March 2015

Summary
Downhole temperature measurements, either by permanent sensors or temporarily conveyed tools, provide information that has been used in many production-diagnosis applications. This paper presents a study that correlates the temperature behavior to the flow profile in a multistage-fractured horizontal well. The ultimate goal is to interpret well performance and to optimize fracture-treatment design from monitored temperature data.
This study has developed flow and thermal models for a system of horizontal wells with transverse fractures under single-phase gas-flow conditions. The system was divided into a horizontal wellbore and a reservoir having multiple fractures. The wellbore-flow and -thermal models were formulated on the basis of mass, momentum, and energy balance. Numerical reservoir simulation was adopted for the reservoir-flow problem, and the reservoir-thermal model was formulated by a transient energy-balance equation, considering viscous dissipation heating and temperature variation caused by fluid expansion in addition to heat conduction and convection. In the reservoir system, the primary hydraulic fractures perpendicular to the horizontal well were modeled explicitly with thin grid cells, and the fracture network around the horizontal well was modeled as an enhanced-permeability zone with respect to the unstimulated-matrix permeability. The reservoir grids between two fractures were spaced logarithmically to capture transient-flow behavior. The reservoir-flow and -thermal models were coupled with the wellbore models to predict the temperature distribution in a horizontal wellbore. The results of the models show two main mechanisms in this thermal problem: head conduction by formation heating/cooling effects at nonperforated zones and wellbore-fluid mixing effects, with reservoir inflow at fracture locations (fluid-entry points).
The examples in the paper illustrate that the models can be used to predict temperature profiles in stimulated horizontal wells for identical or nonidentical transverse fractures. Sensitivity studies were performed to evaluate the influences of fracture conductivity and half-length on temperature behavior in the defined system. The results indicate that the wellbore temperature is sensitive to both the fracture geometry (fracture half-length) and the conductivity across the investigated data range, though they showed different behaviors with time. This work shows that realtime post-fracture temperature-data measurement offers the potential to help evaluate created-fracture parameters, such as fracture conductivity and effective half-lengths.
Environmental Stewardship: Global Applications of a Nonradioactive Method To Identify Proppant Placement and Propped-Fracture Height
Authors: Duenckel R.J.. J. , Palisch T.T.. T. , Han X.. , Saldungaray P.. 
Published: March 2015

Summary
Accurate assessment of intervals receiving proppant and the determination of near-wellbore fracture heights are valuable in assessing and optimizing stimulation strategies. Proppant-placement evaluation in hydraulic fractures has traditionally involved the detection of radioactive (R/A) tracers pumped downhole with the proppant. However, as environmental regulations regarding this technique have tightened, and with increased scrutiny by the public and regulatory bodies of the industry in general and hydraulic fracturing in particular, the need for an alternative to R/A tracers has become paramount.
A new technology for assessing intervals receiving proppant and determining fracture heights by use of a non-R/A detectable proppant has been introduced recently. The technology has found global acceptance and has proved to be a robust and accurate method of locating proppant in the near-wellbore region. In addition to eliminating the safety and environmental concerns with R/A tracers, this new method also provides a permanent indication of the proppant location near the wellbore. Unlike traditional R/A tracers that must be logged before the radioisotopes completely decay, this new method will allow investigation of the proppant pack many years or decades in the future, which will provide critical information during remedial or redevelopment work that cannot be determined with conventional approaches.
A review of the current state of regulatory impediments to the use of R/A tracers in key producing regions around the world is presented, highlighting the need for an alternative diagnostic technology. The technology used in the application of the non-R/A detectable proppant is described, and comparisons with other fracture-diagnostic technologies are presented. Several case histories are shown that illustrate various applications of the technology in regions around the globe. These case histories include applications performed in Asia, the Middle East, Europe, and North America. In addition to identifying proppant location and fracture height, this technology can be used in other applications such as the evaluation of gravel-pack quality. If the current trends in regulatory actions related to hydraulic fracturing continue, it is anticipated that the use of R/A tracers will be restricted to fewer and fewer locales. At the same time, reliable fracture diagnostics for optimization of hydraulic fracturing, from both a wellperformance and a cost-control standpoint, remains extremely important.
NUGGETS Gas Field: Pushing the Operational Barriers
Authors: Saha P.. , Parsa A.. , Abolarin J.. 
Published: March 2015

Summary
The Northern Underwater Gas Gathering, Export, and Treatment System (NUGGETS) subsea development in the northern North Sea consists of five gas wells and a 40- to 70-km tieback to the Alwyn platform, with first gas in 2001 and peak gas production of 6 million std m3/d in 2004. Project life was expected to be 10 years, with the main constraints being methanol (MeOH) requirements for hydrate management and sealine minimum turndown.
Because of increasing water production, the wells were shut in one after another, and the field was scheduled to be decommissioned in 2010. At that time, the minimum recommended MeOH concentration was approximately 28% (wt/wt; MeOH/water), which allowed for a maximum water production of 40 std m3/d. Because of a concerted effort to keep gas rates at targets that respected all constraints and to reduce MeOH use to zero, an additional 4.0 million BOE has been produced from NUGGETS. This represents an incremental recovery of approximately 3%. In addition, the field life has been extended, with the possibility of further prospects being tied into the existing facilities.
With MeOH constraints removed, the new issues became subsea-system-life longevity and reservoir management. Current field-operations philosophy is optimized to respect the minimum gas rate per well with or without water production. It is also aimed to manage water coning in the reservoir. The reservoir has very high permeability with kv/kh ≈ 1 and strong aquifer influx. Moreover, numerical and analytical methods were used to investigate the coning.
This paper provides a critical assessment of the methods used from the flow-assurance, well-performance, and reservoir-management points of view. It concludes with a set of observations and recommendations for operators of dry-gas fields with strong aquifers and long subsea tiebacks.
Coal-Seam-Gas Reservoir Surveillance—Extracting Value From Suspended Coreholes, Surat Basin, Queensland, Australia
Authors: Young S.R.. R. , Norton G.F.C.. F.C. , Foo K.J.. J. 
Published: March 2015

Summary
In 2009, QGC (a BG Group company) began developing coal-seam-gas (CSG) feedstock for its new liquefied-natural-gas (LNG) plant and required a subsurface model and field-development plan to underpin the investment case for the project. Fundamental to the modeling process was acquiring appropriate data to calibrate subsurface models and enhance confidence in their predictive quality. As part of an integrated reservoir-surveillance strategy, specific pressure- and temperature-monitoring wells were required.
This paper describes the successful laboratory and field implementation of an innovative completion technique that converts suspended coreholes into reservoir- and aquifer-monitoring wells. The coreholes are re-entered, and vibrating wire piezometers attached to capillary coiled tubing are positioned and cemented in place alongside selected reservoir intervals. The well is then “plugged and abandoned,” and the lease is remediated to leave only a small surface footprint for the data logger and telemetry. The cement is effectively impermeable to fluid movement, but possesses sufficient permeability to transmit reservoir pore pressure to an adjacent piezometer.
Recompletion of coreholes provides a cost-effective means of acquiring valuable downhole data while eliminating the need to drill a well specifically for monitoring in the same vicinity. Data gathered over the reservoir interval (the Walloon Coal Measures) can inform and help resolve reservoir properties on a regional scale, enhance understanding of the contribution to flow, and provide data points to pressure match a reservoir model. Data gathered over the aquifers within Springbok sandstone and Gubbermunda sandstone enable estimates of any CSG-production effects on groundwater.
Semiquantitative Applications of Downhole-Temperature Data in Subsurface Surveillance
Authors: Wu Xingru , Sui Weibo , Jiang Yuanlin 
Published: March 2015

Summary
Permanent downhole-pressure and -temperature gauges have been installed in many intelligent wells worldwide, providing high-resolution and precision surveillance data about the performance of wells and reservoirs. Compared with the pressure data, the temperature data have been underused in the petroleum industry.
In this paper, we first examine the measured downhole-temperature variation caused by the Joule-Thomson effect and infer the true reservoir temperature and the skin history from the temperature data. An analytical relationship between the temperature data and the skin is presented. Through the use of this relationship, many purposeful surveillance studies, such as monitoring the skin change of the well, can be conducted. Examples of such studies will be provided and discussed using some deepwater-field data.
Furthermore, the downhole temperature can be used to detect whether water breakthrough occurs by means of matrix or fracture through use of the thermal retardation factor. When coupled with the production data and pressure-falloff (PFO) tests, the downhole-temperature data can be used to estimate the water-breakthrough time. The application of this analysis is of practical interest for subsea-well development because of the prohibitive costs and high risks of production logging.
Filtration in Frac Packs and Its Impact on Injector Performance
Authors: Hwang Jongsoo , Sharma M.M.. M. 
Published: March 2015

SummaryThe filtration of solids in the injection water in a frac pack is the primary factor controlling the injectivity decline in frac-packed water-injection-well completions. The injectivity may decline rapidly or much more slowly, depending on the degree of frac-pack filtration. The widening and lengthening of frac packs and the associated loss of sand control are affected also. However, there are no experimental data available for the filtration coefficient at high velocities that are typical in frac packs. In this research, the filtration coefficients were measured experimentally in high-velocity flows encountered in frac packs. The solid concentrations and pressure drops across proppant-pack sections were measured and correlated with earlier filtration theory and permeability-decline models. The filtration coefficients were measured at various flow rates and for different proppant sizes. Our experiments show that at high fluid velocities, the filtration coefficient is significantly lower than that estimated from prior correlations that are based on low-velocity filtration.We have developed new empirical correlations for filtration coefficients at high flow rates in frac packs. The improved filtration coefficients were used as the primary input into a well-injectivity model. The proper estimation of the filtration enabled us to more accurately analyze the impact of injection rates and proppant selection on injector performance (i.e., predict long-term injection-well behavior). The effect of particle filtration in the frac pack, and its effect on injector performance, was captured accurately for the first time. The newly presented empirical correlations coupled with a model for frac-pack growth in the injection well allowed us to estimate accurately the fracture dimensions and the long-term water injectivity of frac-packed injectors. These results can be used for frac-pack design, proppant selection, and specification of injection-water quality.
A Mechanistic Slug-Liquid-Holdup Model for Different Oil Viscosities and Pipe-Inclination Angles
Authors: Wang S.. , Zhang H.-Q.. -Q. , Sarica C.. , Pereyra E.. 
Published: March 2015

SummarySlug liquid holdup is one of the most important parameters of slug flow. It is closely related to the average liquid holdup and pressure gradient of slug flow in wells and pipelines. The mechanistic models of Barnea and Brauner (1985) and of Zhang et al. (2003a) are based on the turbulent liquid-slug assumption for low-viscosity oils. However, for high-viscosity oil, the liquid slug is laminar because of the low slug Reynolds number. In this study, a mechanistic slug-liquid-holdup model is developed for low- and high-oil-viscosity slug flows. The model is based on two shear mixings: shear mixing between the slug front and pipe wall and shear mixing between the slug body and liquid film. The model uses slug-flow characteristics that can be calculated by solving the continuity and momentum equations of slug flow. A data bank consisting of 418 slug-liquid-holdup measurements that were obtained from various authors is used to analyze and validate the model. In the data bank, liquid viscosity ranges from 0.0016 to 0.589 Pa·s (1.6 to 589 cp). Pipe-inclination angle ranges from −30° to upward vertical. Pipe inside diameter varies from 5.08 to 10 cm. Statistical evaluations are conducted and compared with predictions of other models, and significant improvement is observed in the performance of the new model.
Development of a Tool to Assess Hydrate-Plug-Formation Risk in Oil-Dominant Pipelines
Authors: Aman Zachary M. , Zerpa Luis E. , Koh Carolyn A. , Sum Amadeu K. 
Published: March 2015

Summary
This work presents a new simple algorithm for the rapid screening of hydrate plug formation risk, using experimental models of gas hydrate plug formation in oil-dominant systems. The algorithm is based on hydrate formation from an emulsified water phase, where resultant hydrate particles may interact to form large aggregates that increase slurry viscosity and pressure drop. Predictions of pressure drop were compared with a hydrate-forming industrial flow loop, resulting in average absolute deviations between model and experiment of less than 5 psi for liquid-phase Reynolds numbers of less than 75,000 and water content below 70 vol% of all liquid.
Tubing Anchors Can Reduce Production Rates and Pump Fillage
Authors: McCoy James N. , Lynn Rowlan O.. , Taylor Carrie A. , Podio A.L.. L. 
Published: March 2015

Summary
Modern completion techniques have greatly increased the production-rate capability of wells. Many wells have the potential to produce more liquid and gas, but the use of tubing anchors in certain wellbore locations chokes the gas flow up the casing and results in increased backpressure against the formation, which restricts production from the well. A gaseous liquid column can form above the tubing anchor and cause high pressure in the gas below the tubing anchor that restricts the liquid and gas flow from the reservoir.
Often, low pump fillage and low production rates are blamed on a poor gas separator, when actually the separator is operating efficiently and is separating the liquid from the gas. In the condition described, all of the liquid in the wellbore below the tubing anchor falls to the pump and is being removed by the pump. The problem is that high pressure in the gas column below the tubing anchor is restricting production from the well. Additional production is available if the high pressure that is restricting production from the formation is removed. The accumulation of a gaseous liquid column above the tubing anchor when constant low pump fillage is observed indicates that liquid exists above the tubing anchor whereas only free gas exists from the tubing anchor down to the pump. Limited liquid production falls down the casing wall, while the casing annulus is almost completely filled with gas if the pump is set below the formation (McCoy et al. 2013).
Field testing with automated fluid-level-measurement equipment to perform liquid-depression tests verifies that a gaseous liquid column exists (Rowlan et al. 2008) above the tubing anchor and a gas column exists below the tubing anchor in wells with high fluid levels, with low pump fillage, and with the tubing anchor located above the pump. These field data were acquired on several wells and are shown to verify the preceding analysis of the well's performance. This fluid-distribution condition is not generally known. Locating the tubing anchor below the pump prevents this condition and will improve production in these wells.
Selected coelomic fluid parameters of sterlet, Acipenser ruthenus L.: effects of light color and photoperiod
Authors: Azarin Hajar , Aramli Mohammad Sadegh , Naderi Fatemeh 
Published: March 2015

Abstract
Light and color have effect physiological aspects of fish such as growth, the neuro-hormonal system, and reproduction. In the present study, the effects of light color and photoperiod on the levels of selected parameters of coelomic fluid (glucose, total protein, cholesterol, calcium, magnesium) of female sterlet (Acipenser ruthenus) were investigated. Thirty-six broodstock were kept in 12 experimental tanks (500 l) for six months. The fish were reared under four different light regimes (two photoperiods of 18L:6D and 6L:18D and two colors - red and blue) at an intensity of 150 Lx (three replicates). Fish reared under the red-long photoperiod had the highest concentration of the selected parameters of the coelomic fluid. Moreover, significant differences were noted in the all the parameters in fish reared under the red-long photoperiod in comparison with fish from the other treatments (P < 0.05). The results indicate that light (color and photoperiod) influences egg quality during the final stage of A. ruthenus reproduction.