bluuebunny/crossref_metadata_2025 huggingface dataset:
Nanoparticle Stabilized CO2 Foam: Effect of Different Ions
Authors: San Jingshan , Wang Sai , Yu Jianjia , Lee Robert , Liu Ning
Published: March 2016

This paper reports the study of the effect of different ions (monovalent, bivalent, and multiple ions) on nanosilica-stabilized CO2 foam generation. CO2 foam was generated by co-injecting CO2/5,000 ppm nanosilica dispersion (dispersed in different concentrations of brine) into a sandstone core under 1,500 psi and room temperature. A sapphire observation cell was used to determine the foam texture and foam stability. Pressure drop across the core was measured to estimate the foam mobility. The results indicated that more CO2 foam was generated as the NaCl concentration increased from 1.0% to 10%. Also the foam texture became denser and foam stability improved with the NaCl concentration increase. The CO2 foam mobility decreased from 13.1 md/cp to 2.6 md/cp when the NaCl concentration increased from 1% to 10%. For the bivalent ions, the generated CO2 foam mobility decreased from 19.7 md/cp to 4.8 md/cp when CaCl2 concentration increased from 0.1% to 1.0%. Synthetic produced water with total dissolved solids of 17,835 ppm was prepared to investigate the effect of multiple ions on foam generation. The results showed that dense, stable CO2 foam was generated as the synthetic produced water and nanosilica dispersion/CO2 flowed through a porous medium. The lifetime of the foam was observed to be more than two days as the foam stood at room temperature. Mobility of the foam was calculated as 5.2 md/cp.
Low Salinity Flooding Trial at West Salym Field
Authors: Erke S. I. , Volokitin Y. E. , Edelman I. Y. , Karpan V. M. , Nasralla R. A. , Bondar M. Y. , Mikhaylenko E. E. , Evseeva M.
Published: March 2016

Low-salinity waterflooding (LSF) has been recognized as an IOR/EOR technique for both green and brown fields in which the salinity of the injected water is lowered for particular reservoir properties to improve oil recovery. While providing lower or similar UTC's low salinity projects have the advantage of lower capital and operational costs as compared to some more expensive EOR alternatives.

This work describes LSF experiments, field-scale simulation results, and conceptual design of surface facilities for West Salym oil field. The field is located in West Siberia and is on stream since 2004. Conventional waterflooding was started in 2005 and current water cut is currently above 80% in the developed area of the field. To counter oil production decline a tertiary Alkaline-Surfactant-Polymer (ASP) flooding technique selected for mature waterflooded field parts and piloting of this technique is ongoing. Operationally simpler and more cost-effective LSF method is considered for implementation in the unflushed (green) areas of the field since it has been recognized that application of LSF in secondary mode results in better incremental oil recovery than LSF in tertiary mode.

The results of a comprehensive conceptual study performed to justify the LSF trial are presented in this paper. To generate production forecast for LSF in the isolated area at the outset of reservoir development the results of laboratory core tests executed at different salinities presented earlier (Suijkerbuijk et al., 2014) have been used. Dynamic reservoir modelling using low-salinity relative permeability curves showed that injection of low-salinity water leads to incremental oil production up to 2.5% of STOIIP. These results establish the fundamentals for a LSF field trial. A concept of surface facilities design for LSF trial area at West Salym oil field is also presented in the paper. Differently to other LSF projects it is proposed to prepare low-salinity water with required properties by mixing fresh water from aquifer and high salinity water from produced water reinjection (PWRI) system. In such a case LSF facilities concept does not require expensive water treatment techniques which significantly reduces the project capital and operational costs.
Reservoir Management in Howard-Glasscock Field: Waterflood Redevelopment in a 90 Year Old Field
Authors: Smith Cameron , Chapman Shay , Lopez Jorge
Published: March 2016

This paper presents the integrated approach for the redevelopment of the waterflood in Howard-Glasscock field located primarily in Howard County, Texas. Originally discovered in 1925, the majority of production is now commingled across the Guadalupe, Glorieta and Clearfork formations. This is a mature field which is currently in the midst of a 5 and 10 acre infill drilling program that began in 2009. Emphasis has primarily been focused on drilling producing wells, but the basis for this project was to optimize an existing waterflood to guide the development strategy of the field moving forward.

A study of the production of the wells drilled since 2009 identified stronger performance in wells with offset waterflood support. On average, waterflood was responsible for a 22% improvement in the expected recovery per well, despite a lack of patterns or a comprehensive waterflood management plan. As a result, a multi-disciplined team was commissioned to design a strategy for the redevelopment of the flood and more active management of the daily operations. Geology and reservoir engineering aspects were used to characterize the reservoir in conjunction with classical waterflood methods to understand the current performance and validate the expectations for secondary recovery.

Fracture orientation was studied based on cases of early breakthrough and was utilized in pattern identification and well placement to maximize sweep and discourage direct communication between injectors and producers. Further, the success of the waterflood in Howard-Glasscock relies on the ability to control the flow of water over a 2,000 foot vertical interval. To address this, the team has implemented a surveillance plan with improved monitoring and communication with the operations team to enhance the collection of data and in order to react to the dynamics of a waterflood. The rapid response to injection observed in this field requires proper surveillance and timely control of water flow which ultimately drives the success of the program by moving water from high water cut intervals to bypassed oil zones.

This paper details the systematic approach that was used to design the redevelopment plan for a waterflood in a 90 year old field. The scope of work is being implemented and represents an adjustment in the development plan of Howard-Glasscock moving forward. Ultimately, the enhanced performance observed in recent drilling programs and the continued success of development in this mature field hinges on understanding and managing the waterflood moving forward.
Nanoparticle-Stabilized Natural Gas Liquid-in-Water Emulsions for Residual Oil Recovery
Authors: Griffith Nicholas , Ahmad Yusra , Daigle Hugh , Huh Chun
Published: March 2016

Interest in silica nanoparticle-stabilized emulsions, especially those employing low-cost natural gas liquids (NGLs), has increased due to recent developments suggesting their use leads to improved conformance control and increased sweep efficiencies. When compared to conventional emulsion- stabilizing materials such as surfactants, nanoparticles are an inexpensive and robust alternative, offering stability over a wider range of temperature and salinity, while reducing environmental impact.

Oil-in-water emulsions with an aqueous nanoparticle phase and either a pentane or butane oil phase at a 1:1 volume ratio were generated at varying salinities for the observations of several emulsion characteristics. The effects of salinity on the stability of silica nanoparticle dispersions and NGL emulsions were observed. Increasing the salinity of the aqueous nanoparticle phase resulted in an increase in effective nanoparticle size due to increased nanoparticle aggregation. Rheology tests and estimates of emulsion droplet sizes were performed. Shear-thinning behavior was observed for all emulsions. Furthermore, overall emulsion viscosity increased with salinity. Nanoparticle-stabilized liquid butane-in-water emulsions were also generated with varying brine concentrations; however, no rheology or droplet size measurements were made due to the volatility of these emulsions.

Residual oil recovery coreflood experiments were conducted (using Boise Sandstone cores) with nanoparticle-stabilized pentane-in-water emulsions as injectant and light mineral oil as residual oil. A recovery of up to 82% residual oil was observed for these experiments. By continuously measuring the pressure drop across the core, a possible mechanism for enhanced oil recovery is proposed. Pentane emulsion coreflood tests indicated that at a slower injection rate, residual oil recovery increases. This contrasts viscous emulsion corefloods (mineral oil or Texaco white oil as the emulsion oil phase), where increasing the injection rate increases the residual oil recovery.
Improving Oil Recovery in Offshore Heavy Oil Underlain by Large Aquifer
Authors: Qin Wenting , Luo Pingya , Wojtanowicz Andrew K.
Published: March 2016

Many offshore heavy oil reservoirs underlain by large aquifer are developed through cold production method: horizontal wells, with water coning/cresting being a major concern. Inflow Control Devices (ICDs) are often used to delay the water breakthrough by balancing the well inflow along the well section. However, ICDs have difficulties to mitigate the water coning/cresting after water breakthrough, leading to water bypass oil, premature well abandonment and low oil recovery. In this study, we propose the use of a dual completion technology, Bilateral Water Sink (BWS), assisted with ICDs to mitigate water coning/cresting in high water cut wells, therefore improving oil recovery for offshore heavy oil underlain by large aquifer.

To investigate the reservoir performance under this new production technique, a series of experiments were conducted in a scaled Hele-Shaw model, similar to a cross-section of horizontal wells. Identical flow behavior at each cross-section perpendicular to the well axis were assumed. The experiments resemble to the situation in which the ICDs have been successfully implemented to provide a uniform flow along the entire well section. The oil recovery, water cut and reservoir pressure were measured in each runs to quantify the effects of BWS wells on water coning/cresting mitigation and improving oil recovery.

The experimental results show that while ICDs mitigate the non-uniform production profile along the horizontal well section, BWS wells mitigate the water coning/cresting by dynamically modifying the pressure distribution in the reservoir. Experimental results also verify that the previously derived theoretical rates in BWS can efficiently suppress the water coning/cresting after water breakthrough. The quantitative and qualitative results demonstrate that BWS could reduce the water cut from over 95% in high water cut horizontal wells to less than 40 % and improve the heavy oil recovery about 4-6 times compared with that of conventional horizontal wells.

Those findings provide a new insight into offshore heavy oil production mechanism. Because of BWS's ability of converting an original bottom water drive system to a more effective edge water drive system, low water cut and high oil recovery can be achieved by utilizing the reservoir energy without using of heat.
Nanoparticle-Stabilized Emulsions for Improved Mobility Control for Adverse-mobility Waterflooding
Authors: Kim Ijung , Worthen Andrew J. , Lotfollahi Mohammad , Johnston Keith P. , DiCarlo David A. , Huh Chun
Published: March 2016

The immense nanotechnology advances in other industries provided opportunities to rapidly develop various applications of nanoparticles in the oil and gas industry. In particular, nanoparticle has shown its capability to improve the emulsion stability by generating so-called Pickering emulsion, which is expected to improve EOR processes with better conformance control. Recent studies showed a significant synergy between nanoparticles and very low concentration of surfactant, in generating highly stable emulsions. This study's focus is to exploit the synergy's benefit in employing such emulsions for improved mobility control, especially under high-salinity conditions.

Hydrophilic silica nanoparticles were employed to quantify the synergy of nanoparticle and surfactant in oil-in-brine emulsion formation. The nanoparticle and/or the selected surfactant in aqueous phase and decane were co-injected into a sandpack column to generate oil-in-brine emulsions. Four different surfactants (cationic, nonionic, zwitterionic, and anionic) were examined, and the emulsion stability was analyzed using microscope and rheometer.

Strong and stable emulsions were successfully generated in the combinations of either cationic or nonionic surfactant with nanoparticles, while the nanoparticles and the surfactant by themselves were unable to generate stable emulsions. The synergy was most significant with the cationic surfactant, while the anionic surfactant was least effective, indicating the electrostatic interactions with surfactant and liquid/liquid interface as a decisive factor. With the zwitterionic surfactant, the synergy effect was not as great as the cationic surfactant. The synergy was greater with the nonionic surfactant than the zwitterionic surfactant, implying that the surfactant adsorption at oil-brine interface can be increased by hydrogen bonding between surfactant and nanoparticle when the electrostatic repulsion is no longer effective.

In generating highly stable emulsions for improved control for adverse-mobility waterflooding in harsh-condition reservoirs, we show a procedure to find the optimum choice of surfactant and its concentration to effectively and efficiently generate the nanoparticle-stabilized emulsion exploiting their synergy. The findings in this study propose a way to maximize the beneficial use of nanoparticle-stabilized emulsions for EOR at minimum cost for nanoparticle and surfactant.
Experimental Studies and Modeling of Foam Hysteresis in Porous Media
Authors: Lotfollahi Mohammad , Kim Ijung , Beygi Mohammad R. , Worthen Andrew J. , Huh Chun , Johnston Keith P. , Wheeler Mary F. , DiCarlo David A.
Published: March 2016

The use of foam in gas enhanced oil recovery (EOR) processes has the potential to improve oil recovery by reducing gas mobility. Nanoparticles are a promising alternative to surfactants in creating foam in the harsh environments found in many oil fields. We conducted several CO2-in-brine foam generation experiments in Boise sandstones with surface-treated silica nanoparticle in high-salinity conditions. All the experiments were conducted at the fixed CO2 volume fraction (g = 0.75) and fixed flow rate which changed in steps. We started at low flow rates, increased to a medium flow rates followed by decreasing and then increasing into high flow rates. The steady-state foam apparent viscosity was measured as a function of injection velocity.

The foam flowing through the cores showed higher foam generation and consequently higher apparent viscosity as the flow rate increased from low to medium and high velocities. At very high velocities, once foam bubbles were finely textured, the foam apparent viscosity was governed by foam shear-thinning rheology rather than foam creation. A noticeable "hysteresis" occurred when the flow velocity was initially increased and then decreased, implying multiple (coarse and strong) foam states at the same superficial velocity.

A normalized generation function was combined with CMG-STARS foam model to cover the full spectrum of foam flow behavior observed during the experiments. The new foam model successfully captures foam generation and hysteresis trends observed in presented experiments in this study and other foam generation experiments at different operational conditions (e.g. fixed pressure drop at fixed foam quality, and fixed pressure drop at fixed water velocity) from the literature.

The results indicate once foam is generated in porous media, it is possible to maintain strong foam at low injection rates. This makes foam more feasible in field applications where foam generation is limited by high injection rates (or high pressure gradient) that may only exist near the injection well. Therefore, understanding of foam generation, and foam hysteresis in porous media and accurate modeling of the process are necessary steps for efficient foam design in field.
Modeling Relative Permeability Variations in Three-Phase Space
Authors: Kianinejad Amir , Chen Xiongyu , DiCarlo David A.
Published: March 2016

Three-phase relative permeability can vary greatly from two-phase relative permeability as mechanisms such as flow coupling, double displacement, and layer drainage flow regime play a role in three-phase flow. These are on top of the dependency of three-phase relative permeability on two saturations and saturation path/history. The net result is that it is difficult to model/predict relative permeabilities in three-phase space. In this work, we present three-phase oil relative permeability data measured along 11 saturation paths, in a water-wet consolidated (Berea sandstone) and unconsolidated (sandpack) porous media. These saturation paths cover a wide swath of the three-phase saturation space, providing a better physical understanding of the complete three-phase phase space. Three different oils (crude oil, mineral oil, and n-octane) are used in the experiments; the varying viscosities, spreading coefficients, and composition of the oils allows us to investigate the effect of different drainage mechanisms on relative permeability curves. Our data show that there are significant variations between the curves depending on the media, final water saturation, and fluids. In particular, when the media and fluids are held constant, oil relative permeability can vary an order of magnitude at the same oil saturation, depending on the initial condition and water saturation. We find that within each media, all the curves represent a similar shape, but reach to a different residual saturation. This suggests that residual oil saturation is the key parameter in observed relative permeability differences along different saturation paths. We examine this hypothesis with the most common three-phase relative permeability models, i.e. Saturation Weighted Interpolation, Stone I and II, where we vary residual oil saturation to fit the experimental data. We find that if residual oil saturation is used as a fitting parameter, the models predict experimental data well. Otherwise, without varying residual oil saturation, these relative permeability models perform poorly in predicting experimental data.
Results of ASP Pilot in Mangala Field: A Success Story
Authors: Pandey Amitabh , Koduru Nitish , Stanley Matthew , Pope Gary A. , Weerasooriya Upali P.
Published: March 2016

The Mangala field in the state of Rajasthan of western India was the first major oil discovery in the Barmer basin and is the largest discovered oil field in the basin. It contains paraffinic oil with average viscosity of ~15 cp and wax appearance temperature only about 5°C lower than reservoir temperature of 65°C. The initial development plan was a hot waterflood to prevent any in situ wax deposition; recently, though chemical EOR methods have started to play an important role in the development of the field.

A polymer flood pilot was successfully conducted in the field. It was followed by an ASP pilot trial which used the same set of wells. Unlike the polymer pilot, ASP injection was confined to a single continuous sand to reduce interference with nearby wells and to reduce the uncertainty in interpretation of pilot results. A combination of a high molecular weight branched alcohol PO-EO sulfate and a high carbon number sulfonate was selected for the ASP formulation. The selected surfactants functioned well in the desired salinity range and were stable in an aqueous solution up to half a percent higher alkali concentration than the optimal concentration.

The pilot facilities needed to meet a number of challenges arising from using neat surfactants-mainly handling of viscous/gelling material, maintaining accurate dosing rates, maintaining the right ratio of two surfactants, and maintaining stability of the sulfate itself. These challenges were surmounted in the pilot by using a blended surfactant solution, diluted with water, with activity of 24%.

ASP injection led to mobilization of significant volume of oil in the confined 5-spot pattern. The oil-cut of the central producer increased from 10% to 80%. The oil production rate showed almost an eight fold increase from 50 bopd to nearly 400 bopd. The estimated incremental recovery over polymer flooding is nearly 20% of the pilot STOIIP. Later in the pilot project the expected increase in water-cut was accompanied with the production of the injected chemicals along with rise in the pH of the produced water, indicating that favourable mobility was maintained during ASP injection. Some production challenges were encountered—most notably the failure of the producer's electrical submersible pump (ESP); this required the producer to be put on jet pump intermittently when the ESP was not functioning. The saturation observation wells located within the pattern area showed significant desaturation of oil. Sponge cores acquired after the pilot showed very low remaining oil saturation in the flooded sections. The paper will discuss the pilot operations, monitoring and quality control, the pilot results, and lessons learnt.
Interwell ASP Pilot Design for Kuwait's Sabriyah-Mauddud
Authors: Fortenberry R. , Delshad M. , Suniga P. , Koyassan Veedu F. , Wang P. , Al-Kaaoud H. , Singh B. B. , Tiwari S. , Baroon B. , Pope G. A.
Published: March 2016

Our team has developed a new simulation model for an upcoming 5-spot Alkaline-Surfactant-Polymer (ASP) pilot in the Sabriyah Mauddud reservoir in Kuwait. We present new pilot simulation results based on new data from pilot wells and an updated geocelluar reservoir model. New cores and well logs were used to update the geocellular model, including initial fluid distributions, permeability and layer flow allocation.

From the updated geocellular model a smaller dynamic sector model was extracted to history match field performance of a waterflood pattern. From the dynamic model a yet smaller pilot model was extracted and refined to simulate the 5-spot ASP pilot.

We used this pilot model to evaluate injection composition, zonal completions, observation well locations, interwell tracer test design and predicted performance of ASP flooding. A sensitivity analysis for some important design variables and pilot performance benchmarks is also included. We used multiple interwell tracer test simulations to estimate reservoir sweep efficiency for both water and ASP fluids, and to help us understand how well operations will affect this unconfined ASP pilot. This work details some crucial aspects of pre-ASP pilot design and implementation.
Compositional Modeling of Enhanced Hydrocarbons Recovery for Fractured Shale Gas-Condensate Reservoirs with the Effects of Capillary Pressure and Multicomponent Mechanisms
Authors: Jiang Jiamin , Younis Rami M.
Published: March 2016

There is considerable and timely interest in oil and condensate production from liquid-rich regions, placing emphasis on the ability to predict the behavior of gas condensate bank developments and saturation dynamics in shale gas reservoirs. As the pressure in the near-wellbore region drops below the dew-point, liquid droplets are formed and tend to be trapped in small pores. It has been suggested that the injection of CO2 into shale gas reservoirs can be a feasible option to enhance recovery of natural gas and valuable condensate oil, while at the same time sequestering CO2 underground. This work develops simulation capabilities to understand and predict complex transport processes and phase behavior in these reservoirs for efficient and environmentally friendly production management.

Although liquid-rich shale plays are economically producible, existing simulation techniques fail to include many of the production phenomena associated with the fluid system that consists of multiple gas species or phases. In this work, we develop a multicomponent compositional simulator for the modeling of gas-condensate shale reservoirs with complex fracture systems. Related storage and transport mechanisms such as multicomponent apparent permeability (MAP), sorption and molecular diffusion are considered. In order to accurately capture the complicated phase behavior of the multiphase fluids, an equation of State (EOS) based phase package is incorporated into the simulator. Due to the large capillary pressure that exists in the nanopores of ultra-tight shale matrix, the phase package considers the effect of capillary pressure on phase equilibrium calculations. A modified negative-flash algorithm that combines Newton's method and successive substitution iteration (SSI) is used for phase stability analysis under the effect of capillary pressure between oil and gas phases.

In addition, a lower-dimensional discrete fracture and matrix (DFM) model is implemented. The DFM model is based on unstructured gridding, and can accurately and efficiently handle the non-ideal geometries of hydraulic fracture in stimulated unconventional formation. Optimized local grid refinement (LGR) is employed to capture the extremely sharp potential gradient and saturation dynamics in the ultra-tight matrix around fracture.

We apply the developed simulator to study the combined effects of capillary pressure and multicomponent storage and transport mechanisms that are closely associated with the phase behavior and hydrocarbon recovery in gas-condensate shale reservoirs. We present preliminary simulation studies to show the applicability of CO2 huff-n-puff for the purpose of enhanced hydrocarbons recovery. Several design components such as the number of cycles and the length of injection period in the huff-n-puff process are also briefly investigated.
Optimized Cement Systems and Placement Techniques for Tight Clearance Liners
Authors: Verbakel Roeland , Salazar Jose , van Aerssen Mark
Published: March 2016

In a challenging well in a mature gas field offshore Germany, four different size liners with annular clearance of less than 1-in. with the open hole or previous casing were cemented. Successful cementing of these liners was critical in order to drill and complete the well before putting it into production.

To avoid lost circulation during cementing, we established loss-free mud circulation rates before the cementing operation and designed cement slurries with long thickening times for placement at low rates. Additionally, we used fibers in the cement slurry, and pumped treated micronized barite drilling fluid ahead of the cement slurry to lower friction pressures and optimize mud removal.

We validated cement slurry designs through a rigorous laboratory testing procedure, including go/no-go procedures in the high temperature/high pressure (HPHT) consistometer. Long thickening times were needed, especially on a 600 m long 6-in. expandable liner cement job. We tested the setting times of cement accurately with ultrasonic cement analysis and static gel strength analysis devices. Additives to reduce the risk of gas migration were included in all cement slurries.

In order to optimize mud removal and reduce the chance of cement slurry getting contaminated, custom made centralizers were strategically placed in highly critical areas. We optimized spacers through a full laboratory analysis of compatibility between spacer and the low-toxic oil based mud, as well as performing reverse emulsion and grid tests. We validated the mud removal design with 2-D simulations to predict the effectiveness of mud displacement from the wellbore.

Cement slurry was placed without losses on all liners. In all cases, we had positive indications that cement slurry reached up to the liner hanger by observing cement slurry in the returns back to surface. All formation integrity tests on the liner shoe were successful and allowed drilling of the consecutive section. The final production liner was logged using a radial bond tool and advanced cement evaluation processing was run on the data in order to better evaluate cement quality. Good cement bond quality was observed behind the production liner.
Visualization and Quantification of Fluid Flow through Degraded Cement Sheaths
Authors: Skorpa Ragnhild , Vrålstad Torbjørn
Published: March 2016

Cement sheath integrity is important to maintain zonal isolation, as the annular cement sheath is considered to be one of the most important well barrier elements in the well, both during production and after well abandonment. It is however well known that cement sheaths degrad over time, e.g. from repeated temperature variations during production, but the link between the actual leakage rate and the degradation of cement sheaths have not yet been established.

In this paper, we have mapped actual leak paths of degraded cement sheaths, created by thermal cycling experiments, by X-Ray Computer Tomography (CT). The resulting leak path was imported into a Computational Fluid Dynamics (CFD) simulation software, making it possible to determine flow rates of various fluids through actual degraded cement sheaths. The pressure drop over the cement sheath was used as boundary condition of the system. Pressure driven flow through two degraded cement shetats was studied using methane gas as model fluid. The degree of degradation of the cement sheaths varied from systematically connected cracks to real microannuli. The flow through a system of connected cracks compared to a flow through true micro annuli was found to differ by orders of magnitude.
Dynamic Simulation of Gas Migration in Marine Risers
Authors: Velmurugan Naveen , Godhavn John-Morten , Hauge Espen
Published: March 2016

The main objective of this work is to study the dynamic behavior of gas expansion in marine risers. The term ‘riser equilibrium' is used to provide a more rational explanation of gas expansion and its relation to riser unloading. While handling a gas kick situation with the blowout preventer closed, the gas within the riser expands until its pressure equals the hydrostatic pressure of the mud column above, plus any applied back pressure. Buoyancy or slip will cause the gas to migrate, which in turn will cause further expansion, if allowed to, or an increase in pressure. But after a certain point, termed as ‘Riser Equilibrium Point', any small decrease in the hydrostatic pressure would trigger the gas to expand rapidly until enough back pressure is applied or the top of the gas reaches surface. This could cause an explosive unloading. Complete dissolution of gas in oil based muds and the relative delay in noticing any surface indications for the gas influx makes influx detection more complicated with oil based mud as opposed to water based mud. Estimation of various parameters to study these phenomena and their correlation to the gas expansion is studied through an analytical and iterative approach. All schemes are implemented in Matlab and give a basic understanding of the severity of the situation. Calculation of the riser equilibrium point is beneficial to understand the risks related to riser unloading and riser collapse through proper estimation of collapse load. Since the conventional ‘free gas' approach to calculate surface volume of gas during kill operations tend to overestimate the risks involved, this study is expected to provide a more comprehensive understanding of the situation providing a safer operational conditions to handle gas in risers.
Kick Detection Capability of Oil-Based Muds in Well Control Situations
Authors: Linga Harald , Torsvik Anja , Saasen Arild
Published: March 2016

The understanding of kick and gas - oil-based drilling fluid (OBDF) interaction is essential for the planning and operational safety of drilling. The capability to detect gas kick at an early stage and to estimate the gas kick severity is critical.

In this respect the two classes of OBDFs are investigated, one with normal mineral base oil, and the other with linear paraffin base oil. The latter is often used in HPHT drilling applications.

The gas kick detection characteristics is determined by experimental studies of the methane-OBDF equilibrium conditions at pressure and temperature conditions ranging from STP conditions to conditions relevant for HPHT; 200 °C/1000 bar. The OBDF gas loading characteristics is derived from the determination of the two-phase envelope of methane and OBDF. The two-phase envelope towards single phase liquid is determined for selected temperatures and gas mass fraction of methane in the gas-liquid mixture. The equilibrium conditions are studied for both the two OBDFs and the associated classes of base oils; normal mineral base oil and linear paraffin base oil.

It is observed that the maximum methane gas loading capabilities for the two OBDFs are quite similar and follow a linear relation between max gas mass loading in the liquid vs. pressure at pressure below 400 bar. However at higher pressures the performance of the OBDFs differs distinctively, where far more gas can be absorbed in the OBDF with linear paraffin base oil. This OBDF enters into the dense phase region at pressures exceeding 400-450 bar, for which the solubility of gas into the liquid goes to infinity. The dense phase region is encountered at somewhat 100 bar higher with the normal mineral base oil, reflecting fare more attractive characteristics when it comes to the capability for gas kick detection and well control.

The findings illustrate that the selection of base oil for OBDF has an impact on the kick detection capability at HPHT as the gas loading capability and the dense phase region depends on the class of base oil selected for the OBDF. The results also indicate that the operational procedures should be adjusted according to which type of OBDF is used.
Plug and Abandonment Solution for Oilfield Decommissioning in the North Sea
Authors: Aguilar P. , Johnson C. R. , Salazar J. , Bogaerts M.
Published: March 2016

When wells have come to the end of their lives, it becomes necessary to plug and abandon them and return the seabed to its original condition. In the UK sector of the Central North Sea (CNS), an operator managed 6 fields comprising a total of 30 subsea wells in 7 clusters, required to be plugged and abandoned. These fields are among many that are coming to the decommission stage, with the over-riding requirement from the UK government being that of no leakage of hydrocarbons to the environment or between separate permeable geological zones.

The operator standards required the placement of two cement barriers of a minimum of 100-ft each for zonal isolation. The preferred route was to find the annular portion of the barrier by interpretation of ultrasonic imaging tool in combination with the cement bond (CBL) wireline logs used for cement evaluation service, then to set a 500-ft plug inside the casing opposite that zone. In the case that no barrier quality cement was identified in the annulus, section milling of the casing was undertaken to expose 100-ft of formation over which cement was placed.

A number of challenges were faced to design the cement slurry prior to the logging results. The setting depth may only have been confirmed a few hours before the cement job. To cover the possible setting depths and temperature ranges, laboratory testing consisted of performing temperature sensitivity tests on base slurries designed with a wide temperature range retarder, but still optimizing the system to minimize wait on cement (WOC) time.

A specialized high magnesium resistance (HMR) cement system that provides long-term zonal isolation and protects against cement degradation was identified as being best solution. The HMR cement is a blend of blast furnace cement and fly-ash, which reduces the cement permeability and limits the effect of alkaline brine corrosion.

Optimal plug placement was also required for long-term isolation. Specialized plug placement software that accounts for in-pipe and annular contamination, and fluid interface matching during pulling out of the plug was utilised. The slurry design and emplacement best practices will be summarized in this paper.

These subsea wells have been successfully plugged and abandoned by laying temporary, primary, secondary and environmental cement barriers by several different methods: inside casing, across section-milled windows, multi-annular, through scaled production tubing and through coiled tubing according to each particular well's condition. Success ratio was exceptionally high with all the long term barrier themselves being flawlessly placed and verified without any repeat job being required.
Use of Specially Treated Micronized Barite Fluid System with Wellbore Strengthening Approach to Drill Extremely Depleted Reservoir - HPHT Kvitebjørn Field, Offshore Norway
Authors: Ay Ahmet , Sagberg T. , Gyland K. R. , Askø Arne , Jordal Ole Henrik , Døssland Ørjan
Published: March 2016

The HPHT well, A-16A, was planned to test a certain part of the Kvitebjørn field in the North Sea for hydrocarbons in order to prove sufficient reserves to justify a field development. Drilling fluid selection and optimization in the planning phase was considered to be one of the key factors to be able to drill the pilot slim hole section through the Deco/Brent and Cook formations which brought challenges above the standard Kvitebjørn wells due to the risk of high depletion combined with high initial pressure.

The well was planned with a pilot hole, A-16, in order to test the drillability of the overlying strata and prove the absence of highly depleted sand formations. It was important to penetrate all possible depleted zones in the pilot well to verify that sidetrack can be drilled to produce from the Statfjord target. Oil based drilling fluid weighted with treated micronized barite (OB TMB) together with a wellbore strengthening approach was successfully implemented to achieve the pilot well goals.

Managed pressure drilling (MPD) and rig assist snubbing (RAS) equipment were rigged up and the 5 ¾-in pilot section was drilled through a 7-in temporary upper completion (TTRD) set in 9 7/8-in casing. MPD and RAS technologies were used in order to control the bottomhole pressure accurately and to ensure that the additional two barriers were maintained in the well at all times, even if the primary fluid barrier was lost due to crossflow.

The paper provides detail about the drilling fluid planning and execution for the pilot slim hole section; this includes the fluid design and work performed to select and optimize wellbore strengthening materials (WSM) package. The WSM package was optimized by sophisticated, formation fractured, laboratory tests based on the fracture size estimated by proprietary software. Initial formation losses observed while drilling were cured with the particles kept continuously in the fluid, which eliminated the use of extra lost circulation material (LCM) pills or cement slurries. The section was then drilled with more than 500 bar (7252 psi) hydrostatic overbalance (including MPD back pressure), with no further formation losses and without differential sticking incidents while taking pressure points in the extremely depleted zones.

The interval was drilled through extremely depleted formations with the highest overbalance drilling in the operator's experience. Superior integrity of the WSM prevented losses and minimized fluid treatments; this reduced the overall costs with minimal logistics. Low density (~1.5 specific gravity) WSM prevented particle settling in the well or in the drillstring and within the surface equipment, which proved the reliability of the design for MPD sections.
Carbon Dioxide Injection and Resultant Alteration of Weber Sandstone (Pennsylvania-Permian), Rangely Field, Colorado
Authors: Bowker K. A. , Shuler P. J.
Published: March 2016

Geologic interpretations made during the current EOR (enhanced oil recovery) project at Rangely field (Rio Blanco County, Colorado), have made interesting connections between alteration of reservoir mineralogy and texture, changes in produced water composition, and increased production problems.

Carbon dioxide is being injected into the Weber Sandstone in portions of Rangely field. The carbon dioxide injection is part of a very successful tertiary recovery project initiated in late 1986. The bottom-hole pH of Weber brine has decreased from approximately 7.5 to 4.5 with the addition of C02. At Rangely, the Weber is composed mostly of fine-grained eolian sandstone with intercalated (and nonproductive) fluvial sandstones, siltstones, and shales. Much of the Weber is partially cemented with carbonate minerals, including ferroan calcite and ferroan dolomite. Clay minerals, predominantly illite, are also present.

Changes in the chemistry of produced water are associated with alteration of reservoir mineralogy. The C02 flood has caused a substantial increase in the concentrations of iron, calcium, magnesium, and strontium in the produced brine. The amounts of increase is directly related to the volume of C02 produced in each well. This increase resulted from the dissolution of carbonate cements, authigenic clays, and detrital feldspars. An increase in the calculated scaling potential of the produced water is a result of this change in chemistry. Although barium and sulfate concentrations generally have not changed with the C02 injection, produced water from some wells has experienced large changes in barium and sulfate concentrations. The result is an increased tendency for barite scale to precipitate in these wells. An increase in chloride concentration indicates that previously segregated portions of the reservoir, which contained very saline original formation water, have been accessed by the carbonated brine.
Effect of Indaziflam Applications on ‘Tifway 419’ Bermudagrass Growth
Authors: Jeffries Matthew D. , Gannon Travis W. , Ou Ling
Published: March 2016

Indaziflam {N‐[(1R,S)‐2,3‐dihyrdo‐2,6‐dimethyl‐1H‐inden‐1‐yl]‐6‐(1‐fluorethyl)1,3,5‐triazine‐2,4‐diamine} is a preemergence herbicide for annual weed control in turfgrass systems. Following indaziflam U.S. registration in 2010, sporadic cases of hybrid bermudagrass (HB) injury were reported. Field research was conducted from 2012 to 2014 evaluating indaziflam application rates [16 followed by 16 (28 d), 33, 49, or 65 g a.i. ha−1] and timings (fall‐only, fall‐plus‐spring, or spring‐only) in two environments (reduced sunlight [RS] and full sunlight [FS]) to elucidate their effect on HB growth. In Year 1, differences were not detected, while in Year 2 HB cover varied between environments. In Year 2, HB cover in the RS environment treated with 49 and 65 g ha−1 had 36 and 64% less visual cover 12 wk after initial spring treatment than the FS environment, respectively. Within the RS environment, indaziflam also reduced HB visual cover compared to the nontreated (77% cover). A bioassay study conducted with soil cores collected from field plots suggested HB cover reduction was minimally affected by indaziflam‐soil bioavailability, as perennial ryegrass biomass was not reduced beyond a 2.5‐cm depth. Weather conditions varied between years, with air temperatures ≤0°C occurring more frequently and to a greater magnitude in Year 2. The weather, coupled with reduced solar radiation in the RS environment may have contributed to HB cover reduction in Year 2. Overall, indaziflam applications to established HB in areas with suitable growth conditions were safe; however, unacceptable HB cover reductions were observed in areas with poor growth conditions.

Indaziflam is safe on established bermudagrass grown in appropriate conditions.

Bermudagrass‐indaziflam tolerance decreased when applied in a reduced sunlight setting.

Severe winter climatic conditions exacerbated bermudagrass‐indaziflam injury.
Bone Defect Regeneration by a Combination of a β-Tricalcium Phosphate Scaffold and Bone Marrow Stromal Cells in a Non-Human Primate Model
Authors: Masaoka Tomokazu , Yoshii Toshitaka , Yuasa Masato , Yamada Tsuyoshi , Taniyama Takashi , Torigoe Ichiro , Shinomiya Kenichi , Okawa Atsushi , Morita Sadao , Sotome Shinichi
Published: March 2016

Background:

Reconstruction of large bone defects is a great challenge in orthopedic research. In the present study, we prepared composites of bone marrow-derived stromal cells (BMSCs) and β-tricalcium phosphate (β-TCP) with three novel aspects: proliferation of BMSCs with continuous dexamethasone treatment, cell loading under low pressure, and use of autologous plasma as the cell loading medium. The effectiveness of the resulting composite for large bone-defect reconstruction was tested in a non-human primate model, and the bone union capability of the regenerated bones was examined.

Materials and Methods:

Primary surgery: Bone defects (5 cm long) were created in the left femurs of nine cynomolgus monkeys with resection of the periosteum (five cases) or without resection (four cases), and porous β-TCP blocks were transplanted into the defects. Secondary surgery: Bone marrow aspirates harvested from seven of the nine monkeys were cultured with dexamethasone, and BMSCs were obtained. BMSCs were suspended in autologous plasma and introduced into a porous β-TCP block under low-pressure conditions. The BMSC/β-TCP composites were transplanted into bone defects created at the same sites as the primary surgery. Bone union evaluation: Five regenerated femurs were shortened by osteotomy surgery 8 to 15 months after transplantation of the β-TCP/BMSC composites, and bone union was evaluated radiographically.

Results:

After the primary surgery and treatment with β-TCP alone, one of the five periosteum-resected monkeys and two of the four periosteum-preserved monkeys exhibited successful bone reconstruction. In contrast, five of the seven cases treated with the β-TCP/MSC composite showed successful bone regeneration. In four of the five osteotomy cases, bone union was confirmed.

Conclusion:

We validated the effectiveness of a novel β-TCP/BMSC composite for large bone defect regeneration and confirmed the bone union capability of the regenerated bone.
N-alkane as an internal marker for predicting digestibility of forages
Authors: Sandberg R. E. , Adams D. C. , Klopfenstein T. J. ,   Society for Range Management
Published: March 2016

Independent digestion trials with 5 forages were conducted to compare n-alkane with indigestible acid-detergent fiber (IADF) as internal markers to predict in vivo dry matter digestibility (digestibility). Forages were mixed grasses from subirrigated meadow (meadow), meadow regrowth (regrowth), native range (range), mature mixed grass hay from meadow, and alfalfa (Medicago sativa L.) hay. Meadow, regrowth, and range diets were immature grasses harvested 0.5 hours before feeding. Feces from the meadow hay and alfalfa hay trials were divided to compare freeze drying and oven drying (60 degrees C). All diets were subjected to in vitro fermentation for 0, 48, or 96 hours. N-alkane was separated from samples by 4.5-hour saponification with alcoholic KOH followed by extraction with n-hexane. Indigestible ADF was measured by 96-hour in vitro fermentation followed by ADF extraction. Digestibility estimated by markers was compared with in vivo digestibilities. N-alkane based digestibilities were lower (P < 0.01) than in vivo digestibility for all diets. N-alkanes provided higher estimates of digestibilities than IADF for meadow (P < 0.01), regrowth (P = 0.06), and alfalfa hay (P = 0.06), and lower digestibility for meadow hay (P = 0.02). Digestibilities calculated using n-alkanes for range tended to be higher (P = 0.14) than IADF values. Freeze drying increased (P < 0.01) the amount of n-alkane extracted from alfalfa hay, but did not affect (P = 0.1) the amount extracted from meadow hay. N-alkane disappeared (P < 0.001) from residue collected after 48 hours of in vitro fermentation, but no additional disappearance (P = 0.78) was evident at 96 hours. Neither marker was completely recoverable, although recovery of n-alkane was higher than indigestible ADF for 4 of the 5 forages tested.