bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Analysis of Chemical Processes in Reservoirs Based on the Identification of Injection Water Fraction in Produced Brine
Authors: Ishkov Oleg , Mackay Eric , Sorbie Ken 
Published: September 2011

Abstract
The time and subsequent evolution of injection water breakthrough are some of the main indicators production chemists monitor for. After injected water breaks through, the risk of scaling may significantly change and scale mitigation procedures should be planned accordingly. The fraction of the injection water in the produced brine may only be ascertained from analysis of the produced water samples. So far, however, there has been little discussion about other applications of injection water fraction tracking. In this paper new applications that follow on from accurate knowledge of injection water fraction are proposed.
The calculated injection water fraction may be applied to:
Quickly and accurately identify when injection water breakthrough has taken place and therefore remedial action to prevent scale damage needs to be implemented. Identify which ions are involved in in situ geochemical reactions, and the degree of relative ion deviations; identify ion exchange reactions (Relative Ions Deviations). Detect which formation or formations a well is producing from, and potentially the amount of flow from each layer without the use of downhole flow metering.
Strong evidence of the involvement of barium, sulphate, and magnesium ions in reactions, based on the calculations of the Relative Ions Deviations, has been shown for field data. In another case, application of injection water fraction prompted a re-evaluation of the formation water compositions, and as a result it was discovered that the well was producing from a different formation after re-perforation.
The significant new developments presented in this paper allow analysts to obtain an indication of which ions are involved in the reactions, and the degree of relative ion deviations. Additionally, a technique which identifies which formation or formations the well is producing from is proposed.
Determination of Anhydrite in Reservoirs for EOR
Authors: Lopez-Salinas Jose L , Hirasaki George J , Miller Clarence A 
Published: September 2011

Abstract
Alkali in surfactant flooding can sequester divalent ions and reduce surfactant adsorption. When the alkali is sodium carbonate and anhydrite (or gypsum) is present, the anhydrite will dissolve and precipitate as calcium carbonate. An anhydrite level of only 0.1% in the rock is enough to retard the breakthrough of a 1% sodium carbonate solution by approximately 0.7 pore volume, which would greatly reduce effectiveness of a process having surfactants sensitive to divalent ions. Different alkalis will also react with anhydrite.
A methodology is presented to estimate the amount, if any, of anhydrite present in the reservoir. The method is based on brine software analysis of produced water compositions and inductively coupled plasma (ICP) analysis of core samples. X-ray powder diffraction (XRD) can detect anhydrite when it is abundant, but will not be able to detect the low amounts that can still be harmful to chemical EOR.
Produced water and core samples were analyzed from a high-temperature, high-salinity carbonate reservoir, which is a candidate for surfactant EOR. Ten water analyses were obtained from ten wells in five formations. The formation brines ranged from 3-to-20% of TDS. The reservoir rock was mostly dolomite, and reservoir temperature was about 120°C. The saturation index calculated for all formation waters at high salinity (higher than sea water) was positive, indicating over saturation with anhydrite. The saturation index was calculated with ScaleChem for high salinity and PHREEQC, which is limited to lower salinity. The elemental composition of rock samples dissolved in acid was determined by ICP. The mass percent of anhydrite was computed from the elemental analysis.
When these methods were applied to the dolomite reservoir of interest, they strongly indicated that anhydrite was present in sufficient amounts to preclude use of sodium carbonate in a surfactant recovery process.
Salt-tolerant, Thermally-stable Rheology Modifier for Oilfield Drilling Applications
Authors: Wang Jianzhao , Zheng Jun , Musa Osama M. , Farrar David , Cockcroft Bob , Robinson Alison , Gibbison Robert 
Published: September 2011

Abstract
The enhanced performance of drilling fluids, especially High-Temperature, High-Pressure (HTHP) compatibility, will allow more efficient and safer drilling in challenging environments. A novel class of synthetic polymers has been developed as high performance rheology modifiers (viscosifiers) for water-based HTHP drilling fluids. The leading polymer candidate was shown to be an effective viscosifier, with excellent salt-tolerance and thermal stability compared to conventional viscosifiers used in water-based drilling fluids.
This paper presents the basic characteristics of the newly developed polymeric rheology modifier as well as its rheological and thermal stability properties. The rheological properties of the polymers were studied in fresh water, in brines and in formulated drilling fluids. The novel polymer illustrated a similar thickening efficiency and rheological profile (i.e. shear thinning) to xanthan gum. After thermal aging up to 350~400°F (177~204°C) for 16 hours, drilling fluids based on this polymer were shown to maintain excellent rheology and suspension power.
Understanding the Souring at Bakken Oil Reservoirs
Authors: Holubnyak Yevhen I. , Bremer Jordan M. , Mibeck Blaise A. , Hamling John A. , Huffman Benjamin W. , Klapperich Ryan J. , Smith Steven A. , Sorensen James A. , Harju John A. 
Published: September 2011

Abstract
The souring of oil (increasing concentrations of hydrogen sulfide [H2S] gas) from reservoirs in the Bakken Formation has been observed in the field. Souring of oil presents challenges including but not limited to health and environmental risks, corrosion of wellbore, added expense with regard to materials handling and pipeline equipment, and additional refinement requirements. As such, sour oil and gas have lower profit margin (~10% lower price) than traditional sweet Bakken crude.
The understanding of causes for souring in the Bakken Formation and its timely identification are essential for determining the best operational practices and mitigation procedures at this formation. This paper will present an outline of the research goals, a current understanding of souring at the Bakken, and initial findings. Over the course of this project, the series of case-oriented uncoupled compositional reservoir simulations were developed to research the most probable mechanism of H2S generation in the Bakken Formation. The results of this investigation will be correlated in the future with field data from the Bakken oil field operator and laboratory experiments.
Best Practices for Multi-zone Stimulation Using Composite Bridge Plugs
Authors: Lehr Douglas J. , Cramer David D. 
Published: September 2011

Abstract
Treatment isolation using composite bridge plugs (CP) has been practiced for about 18 years in North America and continues to be among the most economical ways to stimulate horizontal and multi-layer vertical wells. Despite this long experience, many end users still experience problems in these applications because of sub-optimal choices regarding product selection, run-in and removal options, and unrealistic expectations regarding plug life in downhole environments.
This paper will identify best practices for using CPs, based on prior technical papers, field experience, and manufacturers’ published data. These practices maximize the chances of successfully installing and removing CPs in multi-zone treatment applications, improving the economics of oil and gas plays requiring multiple stimulation treatments per well.
As multi-zone completion activity increases in regions outside of North America, treatment applications using CPs will also increase in those regions. Realizing the benefits of using CPs in emerging regions will be achieved by learning about best practices from regions with extensive experience in their use.
Silicon-Based Foamants For Foam Assisted Lift Of Aqueous-Hydrocarbon Mixtures
Authors: Koczo Kalman , Tselnik Oleg , Falk Benjamin 
Published: September 2011

Abstract
Foam assisted lift in gas wells, including gas shale, containing both water and hydrocarbon condensates in significant amounts is difficult because the foam is often unstable. The trisiloxane "superspreader" (TS8EOMe) and SiPE-1 to SiPE-6 experimental silicon-based polyether foamants, all with high surface activity, were tested in lab conditions to explore the possibility of using them in foam assisted lift with high hydrocarbon/water ratios. The surface and interfacial tensions and the stability of the aqueous film between an oil drop inside the solution and the gas phase (the so-called "pseudoemulsion" film), were measured and foam tests were conducted with various methods (sparging, foam beating and malt mixer).
It was found that solutions of TS8EOMe form unstable pseudoemulsion film and therefore do not form stable aqueous foams with high amounts of hydrocarbons (hexanes, octane/decane/dodecane, 1:1:1 blend). The SiPE-1 to SiPE-6 surfactants, however, formed stable pseudoemulsion films and their foams were also stable in the presence of these hydrocarbons and therefore they could be candidates for FAL in these systems. The results of sparge tests (the effect of hydrocarbon phase concentration) could be also explained by film stability and the accumulation of oil drops inside the foam. The effects of mixing rate, temperature, aromatic hydrocarbon and the presence of hydrophobic solids were also observed.
Reducing the Risks and Costs of Highly Deviated and Extended Reach Drilling Through the Application of Formation Pressure While Drilling
Authors: Fey Scott , Fareed Abdul , Mansur Hussen , Marzuki Zulkarnain 
Published: September 2011

Abstract
Extended reach and highly deviated wellbores enable operators to intersect multiple reservoir targets with a single wellbore, a capability that would not have been possible had the well been drilled vertically. The driver for drilling these kinds of wells is to reduce the total cost of developing a field. With advances in drilling motors and rotary steerable systems, drilling these types of wells has become common, but there are still challenges in acquiring sufficient formation evaluation data. Often these wells are drilled in already producing fields where depleted zones will be encountered. This, coupled with the high deviation makes wireline conveyed evaluation risky and expensive, in particular since these well types typically require pipe conveyed wireline operations. Logging while drilling (LWD) tools have been able to provide sufficient petrophysical data for the better part of two decades. It is only in recent years that it has become possible to acquire formation pressure data while drilling and thereby provide critical answers to operator asset teams with regards to fluid type, well-to-well connectivity, and depletion trends.
In a drilling campaign in Southeast Asia two highly deviated wells and two extended reach wells were drilled and evaluated successfully using LWD technology both for petrophysics and also formation testing, with an ultimate economic advantage to the operator compared with wireline logging. A formation pressure while drilling (FPWD) service was used to measure formation pressure and record fluid gradients. This paper details the operator's objectives, perceived challenges, operations planning, and the ultimate execution and real time support that made this application of FPWD technology a success.
Latest Development and Project Utilization of Heater Cable in ESP Production System
Authors: Chung Cameron K. , Cox Don , Dalrymple Larry , Yingst Brad , Russell James 
Published: September 2011

Abstract
It has been more than a decade since heater cables were first introduced to facilitate oil production at the North Slope, in Alaska. Since then, the product has spread to acquire a global presence with successful project implementation in a number of countries. There has been increasing interest expressed in using heater cable products in heavy-oil applications given that such products offer significant benefits in reducing fluid viscosity and, consequently, increases the yield rate of horizontal laterals. This paper focuses on the implementation of heater cables, in both technical and project management perspectives. The theories behind the product including electrical and thermal principles in relation to electrical submersible pump (ESP) production systems will be discussed. In addition, project management data such as equipment requirements and field performance through various case histories are presented.
Interpretation of Hydraulic Fracturing Pressure in Low-Permeability Gas Formations
Authors: Kim Gun-Ho , Wang John Yilin 
Published: September 2011

Abstract
The interpretation of hydraulic fracturing pressure was initiated by Nolte and Smith in the 1980s and remains qualitative. An accurate interpretation of hydraulic fracturing pressures, during injection and after shut-in, is critical to understand and improve the fracture treatment in low-permeability gas formations such as tight sand and gas shale. It would provide additional information about the wellbore and better understanding of the reservoir. In this paper, new models for the accurate calculation of bottomhole treating pressure based on surface treating pressure were first developed. This calculation was determined by incorporating hydraulic pressure, fluid friction pressure, fracture fluid property changes along the wellbore, proppant effect, perforation effect, tortuosity, effect of casing, rock toughness, thermal effect, and pore pressure effect on in-situ stress. New methods were then developed for more accurate interpretation of the net pressure and fracture propagation. The models and results were finally validated with field data from tight gas and shale gas reservoirs.
Scale Control and Inhibitor Evaluation of an Alkaline Surfactant Polymer Flood
Authors: Lo Sho-Wei , Shahin Gordon T. , Graham Gordon , Simpson Caroline , Kidd Sam 
Published: September 2011

Abstract
Scale control during Alkaline Surfactant Polymer flooding can be challenging1,2,3 The effective performance of scale inhibitors is a problem, given the high oversaturation expected due to mixing of injected alkali and formation water. Moreover, ASP creates a high pH condition in the reservoir and at production wells. Selecting an effective inhibitor and achieving a long return profile following scale inhibitor squeeze treatment under these conditions can be difficult. This paper describes the studies performed to address the scale management issues for a field where ASP flooding is planned. Scale prediction was carried out and a list of scale inhibitors was screened through performance testing. A number of ASP-specific factors were taken into account for the modeling and testing, including the injected and expected produced chemical concentration, salinity change and chemical compatibility. The results have shown that under these particular field conditions, a conventional penta-phosphonate can provide effective scale control in this field during ASP flooding. Initial core floods indicated that long squeeze life time can be achieved, but the application of the inhibitor in a typical acid form resulted in severe formation damage. A non-damaging formulation was designed by adjusting the inhibitor concentration and partially neutralizing the inhibitor package. The final testing results of the designed inhibitor package show that an effective scale inhibitor squeeze can be attained in the production wells during ASP flooding. More significantly the work demonstrated that the composition of the produced water (% of ASP injection water) producing from a particular zone has a dramatic impact on the potential squeeze lifetimes.
Analysis of Sulphonated Polymers in Oilfield Brines
Authors: Marshall Kirsty , Kyle Mark , Graham Gordon 
Published: September 2011

Abstract
Residual scale inhibitor analysis in produced waters is recognised as an ongoing challenge for many offshore production environments, particularly for the sulphonated co-polymers. This paper builds on work recently presented in SPE 131100 and describes a number of further developments made to enable rapid, accurate, reliable and robust analysis of sulphonated polymers in oilfield brines. This includes more appropriate solid phase extraction (SPE) techniques which demonstrate near 100% retention of sulphonated polymers from brines of different salinities and therefore negate the requirement for dialysis. Whereas the previous paper focused on bench top SPE (solid phase extraction) techniques which demonstrated very efficient assay in synthetic brines, this work progresses and demonstrates the use of the techniques in real produced waters. This paper then advances further to illustrate the progress made in HPLC based techniques including those using GPC based separation coupled with modern highly-sensitive detectors for more routine / automated assay of sulphonated and other polymeric inhibitors. In summary, the paper will present results and methodologies which enable accurate residual assay of sulphonated co-polymers by both benchtop SPE approaches as well as HPLC approaches in both synthetic and real produced waters. These methodologies therefore remove one of the limitations of sulphonated co-polymers compared with other scale inhibitor species and are expected to form the basis of ongoing residual assay for sulphonated polymers in coming years.
Modeling the Effect of Triazine Based Sulphide Scavengers on the in situ pH and Scaling Tendency
Authors: Goodwin N. , Walsh J.M. , Wright R. , Dyer S. , Graham G.M. 
Published: September 2011

Abstract
Amine-based chemicals used for scavenging of hydrogen sulphide will cause precipitation of carbonate scales, under a wide range of conditions. They are effective as scavengers, and have health, safety and environmental advantages compared to other scavenger chemicals. Unfortunately, they significantly raise the pH of all process waters that they are mixed with, and thus exacerbate the scaling tendencies of dissolved carbonate minerals. Calcium carbonate, magnesium carbonate and iron carbonate scales can occur over a wide range of temperatures, pressures, and carbonate concentrations. In many process configurations there is no alternative but to allow the mixing of scavenger with produced water. In those cases, extensive laboratory work is typically required to select an appropriate scale inhibitor. It is usually necessary in such studies to understand in detail the chemistry of the solution and its pH and alkalinity characteristics.
We have developed a modelling methodology which can approximate the effect of triazine type H2S scavengers using an analogue amine as an effective weak base. The effective weak base has a base dissociation constant of the right order compared to monoethanol amine. It therefore simulates the pH effects, and the titration curves of the amine / CO2 / carbonate buffer system that were measured in the lab. Using this methodology we show how the production process has a significant impact on the in situ scaling potentials and how improved modelling and laboratory tests are able to better simulate the field conditions and aid understanding of the process chemistry issues and solutions.
Optimized Formation Fluid Sampling Supports Reservoir Characterization
Authors: Wa Wee Wei , Karim Rahimah Abd , Acuna Pedro Elias , Haddad Sammy 
Published: September 2011

abstract
Good quality reservoir fluid samples are critical to ensure the accuracy of the captured fluid composition and thus accurate key reservoir fluid properties’ description, namely GOR, saturation pressure, density, and viscosity. Reliable characterization of reservoir fluid properties during the early stages of exploration and development is critical for understanding fluid composition, estimating reserves, and optimizing production or completion strategies.
Miscibility and time limitation allocated by the drillers have been the main challenges in the open-hole sampling. A quick cleaning process and real time monitoring of contamination level are essential in assuring clean reservoir samples. Fluid cleaning process using conventional openhole sampling technique typically required long pumping times to reach acceptable contamination level.
This work presents an optimized wireline sampling technique with full utilization of downhole fluid analysis applications to address the open hole sampling challenges in an offshore Malaysia field. High quality reservoir oil and water samples were required for detailed PVT and flow assurance analyses. The mud type used was water-based mud, which posts a great challenge particularly for water sampling since the fluids are easily miscible. A focused sampling technique was used to accelerate the mud filtrate cleaning process. Different downhole fluid analysis approaches were applied at water and oil sampling station to monitor the reservoir fluid contamination level. At water sampling stations, pH measurement helped to discriminate the clean reservoir water and water based mud filtrate. While at oil sampling stations, flowing fluid optical density differences was monitored to ensure clean formation oil sample. The methodology and applications of all the techniques are discussed in detailed in this work and documented with actual field data and PVT laboratory results.
Results of a New Coiled-Tubing Assessment Tool
Authors: Stanley R. K. 
Published: September 2011

Abstract
A new non-contact CT assessment system was placed in service in 2010, measuring wall thickness, diameter, ovality, and detecting imperfections in the wall of ferromagnetic steel tubing.
The unit is capable of assessing both new tubing for compliance with API 5ST (Specification for Coiled Tubing)1supplementary requirement SR37, and also in-service tubing for erosion, corrosion and other imperfection conditions. The unit has the advantage of being able to assess the effect of flaws on tubing life via the Flexor programme.
A review of results obtained with the new tool when used to assess both new and used CT will be presented. Knowledge of the condition of the tubing at all stages of its life should be of great importance to owners of tubing when deciding upon future tubing use.
Case Study of Core Bit Wear and its Effect on Core Recovery and Quality during Deep-sea Drilling Expeditions
Authors: Shinmoto Y.. , Wada K.. , Miyazaki E.. 
Published: September 2011

Abstract
Scientific deep-sea drilling and coring operations in the Nankai-Trough located offshore Japan have been undertaken to unravel the mechanisms behind earthquakes and tsunami. Throughout a number of expeditions, core sampling runs using an advanced multiple wireline coring system which can continuously core into sections of undersea formations have been carried out. High core recovery and quality are vital to research in undersea formations.
A wireline type rotary core barrel with 10–5/8 inch PDC core bits were deployed in the recent expeditions. However, due to rough sea conditions and severe drilling environment, the PDC core bit cutters were easily worn, causing significantly low core recovery and damaged core samples. The condition of the PDC trim cutters could thus be said to determine the results of the entire operation, showing the need for accurate analysis of the challenges in developing and maintaining drilling equipment and systems.
This study analyzes the bit conditions and how the wear or damage of the PDC cutters affect core recovery and quality. Core quality was analyzed using X-ray-CT Scan image data as a new method of analyzing the quality. The heave motions of the drillship are also shown to affect the core quality and stress or damage while the onset of the core disking phenomenon was also monitored and analyzed.