bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Generation Environment Friendly Water-Based Drilling Fluid and Field Applications
Authors: Zhu Qi , Wang Yong , Zhang Yongqing , Sun Zhihe , Wei Yinghui , Wang Runping 
Published: October 2018

Abstract
Currently, synthetic additives are widely used in drilling fluid, but these additives have hazards, such as, toxicity, difficult to degradation, leakage and volatilization caused great influence to wellsite environment. Environmentally friendly drilling fluid has been appeared around for decade. However, because of high cost of raw materials, lack of adequate supplement and complexity of modified synthetic process, there has been no widespread industrial application in China. The majority of test wells are straight, but deviated well and highly-deviated well test is seldom reported.
A series of indoor evaluation and field applications were carried out in process of modifying low cost additives to the environmentally friendly treatment agents. HTHP aging and filtration experiment to verify temperature resistance; adding sodium chloride to verify anti-salt properties; adding bentonite and cuttings recycling experiment to verify inhibition performance of slurry and mud shale; friction resistance experiment verifies that lubrication capacity meets deviated well and highly-deviated well operations; core flow experiment to verify reservoir protection performance; heavy metal, biochemical oxygen demand, chemical oxygen demand, biological toxicity analysis experiment to verify influence of the system on environment.
Ability of temperature resist 120 °C, anti-salt ability reaches saturation and recovery of cuttings is more than 85%. Environmental performance of the drilling fluid system is ideal, EC50 value is 1.61×105, no biological toxicity, BOD5/CODcr is 0.11, easy biodegradation. Field application for morethan 30 wells, with beyond 20 deviated wells and highly-deviation angle more than 50 ° wells are 10.
The new types downhole tools for speeding-up and controlling hole size, rotary impactor and wellbore cleaner, were used to improve mechanical penetration rate (ROP) and wellbore cleaning. After employing the environment system, the drilling fluid does not need to be transshipped and processed directly in wellsite, and well fields are restored. Drilling fluid disposal process saves the cost of artificial working, transportation and environmental management. This drilling fluid system is first applied on-site in North China, which fills the blanks and provids reliable technical support and reference examples for the subsequent replacement of drilling fluid systems used now in North China.
Alkaline/Surfactant/Polymer Flooding With Sodium Hydroxide in Indiana Limestone: Analysis of Water/Rock Interactions and Surfactant Adsorption
Authors: Tagavifar M.. , Sharma H.. , Wang D.. , Jang S. H. , Pope G. A. 
Published: October 2018

SummaryWe recently used sodium hydroxide (NaOH) in Indiana limestone coreflood experiments to lower anionic-surfactant adsorption. This study presents analysis of the limestone geochemistry and the surfactant adsorption under static and dynamic conditions. Analysis of the effluent ionic composition using ion chromatography and inductively coupled plasma showed the presence of sulfate (SO42−) aluminum (Al), and iron (Fe), as well as calcium (Ca) and magnesium (Mg). To determine the likely source of each geochemical species and to characterize how the dissolution kinetics changes the slug chemistry, PHREEQC was used to inverse-model Indiana limestone rock using the bulk X-ray-diffraction (XRD) mineralogical composition and the influent and effluent water chemistry. Results showed that all Indiana limestone cores contained anhydrite, which was not detected by XRD. The effluent concentration of Al increased with pH to approximately 15 mg/L, whereas Fe concentration remained fairly independent of pH at 0.04 ± 0.02 mg/L. These trends suggest the likely source of Al and Fe to be either clay dissolution or the release of natural clay colloids with NaOH. Simulations suggested that in Fe-bearing carbonates, alkali consumption is fast but limited with NaOH, which is observed as pH-front delay, whereas alkali consumption is slow but severe with sodium carbonate (Na2CO3) resulting in minimal pH-front delay but lower effluent pH compared with influent pH for prolonged injection times. Using the PHREEQC calculations, the ionic composition of the chemical slug in subsequent alkali/surfactant/polymer (ASP) experiments was adjusted. In addition, the coupled adsorption/transport of anionic surfactants in carbonate rocks was also investigated using surface-complexation-model adsorption under static and dynamic conditions. Model predictions agree with the single-phase-adsorption coreflood results and suggest that the adsorption on the metal oxides or clay could be comparable with that on calcite. This arises from the higher surface area and the point of zero charge of pH (pHpzc) of metal oxides.
Surface-Charge Alteration at the Carbonate/Brine Interface During Single-Well Chemical-Tracer Tests: Surface-Complexation Model
Authors: Khaledialidusti Rasoul , Kleppe Jon 
Published: October 2018

Summary
Water chemistry has been shown to affect oil recovery by affecting surface charge and rock dissolution. The single-well chemical-tracer (SWCT) test is a field method to measure residual oil saturation (Sor), in which hydrolysis reaction of an ester has been known as a key process that could displace the equilibrium state of a reservoir by changing formation-water (FW) composition.
Because oil mobilization during the SWCT tests causes an error in the measurement of Sor, changes in water chemistry might be a concern for the accuracy of Sor measurements. In our previous work, the extent to which different reservoir parameters might change water composition and the effect of water-chemistry changes on the calcite dissolution and the oil liberation from the carbonate-rock surfaces were extensively evaluated. In this study, the effect of water-chemistry changes on surface-charge alteration at the carbonate/brine interface has been studied by constructing and applying a surface-complexation model (SCM) that couples bulk aqueous and surface chemistry. We present how the pH drop induced by the displacement of the equilibrium state and changes in water chemistry in the formation affect surface charge in a pure-calcite carbonate rock during the SWCT tests.
The results show that a pH drop during the SWCT tests while calcium concentration is held constant in the FW by ignoring calcite dissolution yields a less-positive/more-negative surface charge so that wettability of carbonate rock might be altered to a less-oil-wetting state, when the oil is negatively charged. In reality, however, calcite dissolves by water-chemistry changes during the SWCT tests, which leads to an increasing calcium concentration in the FW. Consequently, an SWCT test in carbonates is accompanied by increasing calcium concentration while pH drops, which yields an increase in the surface charge of carbonate rocks. Therefore, the pH drop does not directly affect the surface charge of carbonate rock during an SWCT test, and calcium concentration increased from calcite dissolution could control the surface charge more significantly.
Numerical Simulation of Supercritical-Water Flow in Concentric-Dual-Tubing Wells
Authors: Sun Fengrui , Yao Yuedong , Li Guozhen , Li Xiangfang 
Published: October 2018

Summary
Much work has been performed on the modeling of saturated/superheated-steam flow in wellbores. At present, the study on supercritical-water (SCW) flow in wellbores, especially concentric-dual-tubing wells (CDTWs), is very limited.
In this paper, work was performed on modeling of SCW flow in CDTWs. First, a comprehensive mathematical model comprising a pipe-flow model, supercritical-fluid model, and heat-transfer model is established. In the model, the heat exchange between the integral joint tubing (IJT) and annuli is taken into consideration. Numerical solutions of SCW flow in CDTWs were obtained with a straightforward numerical method. Then, sensitivity analysis was conducted. The following results were found:
SCW in annuli (with a higher temperature) releases thermal energy to SCW in the IJT, which causes increase of temperature in IJT. As a result, SCW density in the IJT has a decrease. The density gradient near the wellhead increases with increasing of injection rate. When the injection temperature in the IJT is larger than that in annuli, SCW density increases with well depth near the wellhead.
Buildup-Pressure Extrapolation of a Heterogeneous Reservoir: Application of the Crump and Hite Method to a Real Field Case
Authors: Piccinini R. B. 
Published: October 2018

Summary
Traditional methods of pressure-transient analysis rely on homogeneous reservoir models and require assumptions on reservoir shape and well-flow regimes. Unsteady flow rates offer further complexity because traditional methods are dependent on past production history. Crump and Hite (2008) proposed a new method for estimating average reservoir pressure that applies to heterogeneous reservoirs and only requires knowledge of the pressure-buildup data. The Crump and Hite (2008) method relies on obtaining the first few eigenvalues of a diffusion equation to predict average reservoir pressure. A large buildup time may be required for a successful application of the method, depending on the magnitude of the first eigenvalue.
This work applied the Crump and Hite (2008) method to a real field case. A reservoir was produced by a single horizontal well for a period of a few years, which was followed by a shut-in period of approximately 200 days. The first four eigenvalues could be extracted, providing an estimate of average reservoir pressure. The pressure derivative was computed with a total-variation-regularization method, which showed lower noise levels compared with finite-difference methods. The extended version of the Crump and Hite (2008) method for shorter buildup times did not show a substantial reduction of the buildup-time requirement.
Long-Period, Long-Duration Seismic Events and Their Probable Role in Reservoir Stimulation and Stage Productivity
Authors: Kumar Abhash , Zorn Erich , Hammack Richard , Harbert William 
Published: October 2018

SummaryHydraulic fracturing is a well-established technique to extract gas or liquid hydrocarbons from low-permeability formations such as shale and tight gas reservoirs. Diffusion of hydrofracturing fluid outward from the stimulated fractures into the target formation produces slip across pre-existing fractures and other discontinuities in the rock. Microseismic events recorded by downhole seismic-monitoring arrays are a manifestation of associated deformation. Recent investigations suggest that the total cumulative seismic moment of microearthquakes during hydraulic fracturing is only a small portion of the total seismic-energy release expected for the fluid volume injected into the formation. These observations suggest that other sources of energy release (such as inelastic deformation), contemporaneous with microseismicity, should be considered relevant to the hydraulic-fracturing process. Recent observations on long-period, long-duration (LPLD) seismic events suggest that slow slip emission along weaknesses that are misaligned with respect to the present-day stress field is likely an important mechanism of deformation and should be better understood and quantified in reservoir stimulations. In Morgantown, West Virginia, we conducted seismic monitoring of hydraulic-fracturing activity using an array of five broadband, three-component (3C) surface seismometers. Using this network, we identified 89 high-amplitude, impulsive events and 436 LPLD events, with highly emergent waveform characteristics. In these interpreted LPLD events, we observed a significant concentration of energy in the 0.8- to 3-Hz frequency range. During hydraulic fracturing, LPLD events were found to occur most frequently when the pumping pressure and rate were at or near maximum values. Because the main purpose of hydraulic fracturing is to stimulate oil and gas production from the less-permeable reservoir, we compared the relative production contributions/stage to the frequency of the occurrence of suspected LPLD events. We found a positive correlation between the frequency of LPLD events and stage-by-stage gas production, highlighting the potential contribution of slow deformation processes and its effectiveness in the reservoir stimulation.
Robust Life-Cycle Production Optimization With a Support-Vector-Regression Proxy
Authors: Guo Zhenyu , Reynolds Albert C. 
Published: October 2018

Summary
We design a new and general work flow for efficient estimation of the optimal well controls for the robust production-optimization problem using support-vector regression (SVR), where the cost function is the net present value (NPV). Given a set of simulation results, an SVR model is built as a proxy to approximate a reservoir-simulation model, and then the estimated optimal controls are found by maximizing NPV using the SVR proxy as the forward model. The gradient of the SVR model can be computed analytically so the steepest-ascent algorithm can easily and efficiently be applied to maximize NPV. Then, the well-control optimization is performed using an SVR model as the forward model with a steepest-ascent algorithm. To the best of our knowledge, this is the first SVR application to the optimal well-control problem. We provide insight and information on proper training of the SVR proxy for life-cycle production optimization. In particular, we develop and implement a new iterative-sampling-refinement algorithm that is designed specifically to promote the accuracy of the SVR model for robust production optimization. One key observation that is important for reservoir optimization is that SVR produces a high-fidelity model near an optimal point, but at points far away, we only need SVR to produce reasonable approximations of the predicting output from the reservoir-simulation model. Because running an SVR model is computationally more efficient than running a full-scale reservoir-simulation model, the large computational cost spent on multiple forward-reservoir-simulation runs for robust optimization is significantly reduced by applying the proposed method. We compare the performance of the proposed method using the SVR runs with the popular stochastic simplex approximate gradient (StoSAG) and reservoir-simulations runs for three synthetic examples, including one field-scale example. We also compare the optimization performance of our proposed method with that obtained from a linear-response-surface model and multiple SVR proxies that are built for each of the geological models.
Three-Phase Relative Permeability and Capillary Pressure Models With Hysteresis and Compositional Consistency
Authors: Neshat Sajjad S. , Pope Gary A. 
Published: October 2018

SummaryNew coupled three-phase hysteretic relative permeability and capillary pressure models have been developed and tested for use in compositional reservoir simulators. The new formulation incorporates hysteresis and compositional consistency for both capillary pressure and relative permeability. This approach is completely unaffected by phase flipping and misidentification, which commonly occur in compositional simulations. Instead of using phase labels (gas/oil/solvent/aqueous) to define hysteretic relative permeability and capillary pressure parameters, the parameters are continuously interpolated between reference values using the Gibbs free energy (GFE) of each phase at each timestep. Models that are independent of phase labels have many advantages in terms of both numerical stability and physical consistency. The models integrate and unify relevant physical parameters, including hysteresis and trapping number, into one rigorous algorithm with a minimum number of parameters for application in numerical reservoir simulators. The robustness of the new models is demonstrated with simulations of the miscible water-alternating-gas (WAG) process and solvent stimulation to remove condensate and/or water blocks in both conventional and unconventional formations.
A Dynamic Model with Friction for Comprehensive Tubular Stress Analysis
Authors: Mitchell Robert F. , McSpadden Albert R. , Goodman Malcolm. A. , Trevisan Ruggero , Watts Rick D. , Zwarich Nola R. 
Published: October 2018

Abstract
A new model technique is described for comprehensive dynamic stress and displacement analysis of wellbore tubulars including friction loads. A dynamic model of tubing forces is necessary to predict local pipe velocity which in turn determines the magnitude and direction of localized frictional contact. By tracking dynamic changes in axial force starting from the initial running state, a complete load history may be simulated through the life of the well.
The dynamic friction model subdivides the string joint by joint and uses an elastic pipe momentum balance. Pipe velocity is related to axial force by the elasticity equation. Dynamically determined velocity is necessary to predict magnitude and orientation of local node friction vectors. Damping for the dynamic analysis is provided by annular fluid viscosity. The elastic equations are solved as a set of algebraic equations in terms of past and future values of pipe axial force and velocity. Key model inputs such as pressure, temperature, fluid and wellbore friction coefficients can be changed at each successive load step.
Running loads and packer setting with slack-off or pick-up loads determine the initial string configuration. Given the initial configuration, each subsequent load case is calculated starting from the prior load and resultant friction state, allowing for full history dependence. The surface velocity profile of running individual stands is a key input. Unexpected magnitudes of downhole transfer of surface load are demonstrated. Change in operation load sequence is shown to produce significant differences in tubular axial loads, indicating that special attention to load history should be considered when performing tubular stress analysis. For slack-off, overpull, or packer setting events the model can track dynamic load response at downhole points such as a packer or cement top. An example well with deviated profile and planned sequence of life-cycle operations including stimulation, production and shut-in was simulated for a variety of load sequences. The model has been validated against field data using the actual hook load plot during installation of a single-trip, multi-zone intelligent completion in an offshore highly-deviated ERD well. Example calculations are given for an HPHT subsea well and a horizontal unconventional well.
The dynamic friction model allows for seamless integration of running loads with friction into a fully sequential stress analysis of subsequent well life-cycle loads for landed strings. Current industry models separate installation state from the in-service life envelope. From comparison with appropriate static analytic solutions and industry standard drag and stress models, dynamics were found to affect friction force directions and magnitudes, suggesting that tubular dynamics cannot be neglected.
Accessing New Pay Intervals in the Tubing-Casing Annulus Above Top Packer with Cement Packer Technology, S Field, Peninsular Malaysia
Authors: M. Johan M. Alham , Al Zayani Sirag , Moritz Arthur Lee , Taylor Charles , Wibisono Rahmat , M. Mokhtar Shahril R. , Thian Kelvin , Samvelova Marina 
Published: October 2018

Abstract
As a low-cost alternative to expensive rig workovers, placement of a cement packer between tubing and casing has been previously applied in Malaysia. The purpose is to create a new annular barrier above the existing production packer to gain access to behind-casing opportunities (BCOs) or pay zones, removing the need for a workover. These pay zones, usually with minor or unknown production potential, have been left by the operator during initial completion because there were larger pay zones in deeper reservoirs. Cement packer placement can be achieved using basic intervention equipment as opposed to more expensive workover units.
The cement packer technique eliminates the need of recompleting the well with a conventional workover rig and reduces operational complications together with cost. There are different methods to deploy a cement packer. The highest chance of success, particularly when larger volumes of cement are needed, is using coiled tubing (CT) as the primary method to place the cement slurry in the tubing/casing annulus. In this method, a cement retainer was used and conveyed with CT. CT provides the ability to sting into the retainer and cement being displaced through the coil, ensuring all completion accessories have no contact with cement slurry which can impair their functionality, and also prevents U-tube effect of the slurry once cement is placed behind the tubing. After the cement is set, a cement bond log (CBL) is run to confirm cement integrity behind the completion tubing before adding new perforations.
This paper presents the successful cement packer placement operation with the help of the CT executed on an offshore platform in Peninsular Malaysia. A potential pay zone of the I-Group reservoir was discovered in the field after running pulsed-neutron cased-hole saturation logging tools, which are situated above the production packer; appraisal was required because of the unknown fluid type. Close collaboration among various parties in candidate selection, job preparation and design, cement laboratory testing, and operational planning and execution, were keys to the success of this pilot operation. By proving operational feasibility and economics, the technique opened up additional opportunities in restoring idle wells with bypassed reserves within the same field.