bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Dynamic Surveillance of Deepwater Slope Systems in Block-14, Angola
Authors: Rivera Nestor A. , Drinkwater Nick , Charles Dawari D. 
Published: September 2013

Abstract
Optimal development of deepwater slope system reservoirs in Block-14, Angola, requires proper determination of Original Oil in Place, reservoir connectivity, and lateral heterogeneity. The uncertainty on these parameters can be reduced significantly by using high frequency pressure and production data and pressure versus depth profiles acquired while drilling to augment and calibrate pre-existing interpretation from seismic, cores and logs. The Block-14 Tombua-Landana Drilling and Production Platform was built to develop 8 channelized reservoirs, which have different degrees of heterogeneity and net-to-gross ratios. This variability was recognized early during the development program and resulted in a wide range of initial production rates and declines. In response to this, producers were designed with permanent downhole gauges to improve reservoir surveillance capabilities for better determination of well count and optimal placement of producers and injectors. In addition, real time data integration tools were implemented to facilitate performing real-time dynamic modeling.
Once started operating, downhole and wellhead well-data are transmitted and stored in a data repository. This information is integrated with well-tests and used to calibrate reservoir-to-surface wellbore models and generate real-time production profiles. The workflows capture planned and unplanned shut-ins, are used to perform pressure-transient analysis and determine static pressure. By performing material balance and reservoir simulation modeling, we have been able to determine oil in place, quantify the degree of support from offset injectors, assess interwell connectivity, calibrate and update specific aspects of the geological model and optimize the development plan for each reservoir. These workflows also contributed to predicting well events such as scaling, sand production, and water breakthrough.
This paper describes examples of surveillance and dynamic modeling for wells in the Tombua-Landana (T-L) fields and describe how permanent downhole data has improved reservoir management.
Prevention of Pulsations Caused by Flexible Risers
Authors: Belfroid S. P. , Golliard J. , Korst H. J. 
Published: September 2013

Abstract
In the last few decades, flexible risers have increasingly been used in the offshore oil and gas industry. In gas applications these risers can generate high amplitude tonal pressure fluctuations when the gas velocity reaches a threshold value. The resulting pressure fluctuations can then cause high vibration and cyclic stress levels in the associated topside and subsea pipe work. On a number of platforms, riser pulsations have led to serious limitations of the production capability and in at least one case to the fatigue failure of two small bore side branches, resulting into a shutdown of the platform for five months.
An acoustic assessment is performed to determine the risks of a flexible riser to be a source of Flow-Induced Pulsations (FIP) within its intended operating envelope. This assessment is based on models and methods to predict the onset velocity, pulsation frequency and amplitude and is based on actual field measurements on five different platforms and on research performed in collaboration with multiple operators and universities. Relevant inputs include the riser carcass geometry, operating conditions and the reflective characteristics of the topside and subsea piping. The outcome of the assessment allows for the implementation of corrective measures during the design phase of a project and mitigation strategies for already existing risers.
Inducing Earthquake By Injecting Water In A Gas Field: Water-weakening Effect
Authors: Bois Axel-Pierre , Mohajerani Mehrdokht , Dousi Niek , Harms Stijn 
Published: September 2013

Abstract
On November 26, 2009 a 2.8-magnitude earthquake occurred in southwestern Friesland in the Netherlands at an approximate depth of 2 km. This relatively shallow depth indicated that the event was induced, instead of being natural. Closest mining activities were supposed to be the Weststellingwerf field with well WSF-01 and the exploration well DHV-01. The event was named De Hoeve. However, production from DHV-01 started after the event was occurred. Thus, a study was required to determine the origin of the tremor, evaluate if it could be followed by other tremors in the future, and estimate its magnitude. The objective of this paper is to present the study that was conducted in order to identify whether the gas production and water injection in well WSF-01 could have caused the so-called Weststellingwerf fault to slip leading to the earthquake as observed in November 2009.
The following work plan was devised: 1) Perform seismic interpretation; 2) Construct fit-for-purpose geological model of Weststellingwerf area; 3) Construct reservoir simulation model; 4) History match production data of two wells and record pressure and temperature distribution as a function of time; and 5) Build 2-D geo-mechanical model, feed geological data and structure into model, feed pressure and temperature from dynamic model into geo-mechanical model, assign reasonable geo-mechanical properties, perform stress calculations at critical time steps, and determine potential slip displacement along Weststellingwerf fault.
Five triggering mechanisms were tested: 1) Salt dissolution; 2) Pressure depletion during gas production; 3) Re-pressurization due to water injection; 4) Thermal stresses due to cold water injection; and 5) Fault weakening due to water injection (chemical alteration)
Geo-mechanical simulations showed the causes of the earthquake should be looked for, not in stress variations along Weststellingwerf fault, but instead in a fault weakening upon first contact with water. Two mechanisms can be at the origin of this reduction: fault lubrication or decrease in capillary pressure in the fault gouge material when it was first contacted by water.
The simulations also showed that no earthquake should occur in the section of the fault where displacements occurred during de Hoeve tremor. Sections that did not show any displacement could be at the origin of new earthquakes when first contacted by water, but probably of lower magnitude.
Pressure Pulsing Cyclic Solvent Injection (PP-CSI): A New Way to Enhance the Recovery of Heavy Oil through Solvent-Based Enhanced Oil Recovery Techniques
Authors: Jia Xinfeng , Zeng Fanhua , Gu Yongan 
Published: September 2013

Abstract
Hydrocarbon solvent-based enhanced oil recovery (EOR) techniques, such as vapor extraction (VAPEX) and cyclic solvent injection (CSI), have shown a great potential to recover heavy oil reserves. Solvent dissolution into heavy oil and diluted oil flow are the two main processes of these techniques. VAPEX suffers a low production rate because of the slow mass transfer and inefficient gravity drainage. Although benefited from solution gas drive and foamy oil flow, CSI is bothered with the solvent gas release and viscosity re-increase during the production period, which might seriously slow down the oil production. In this study, it is found that foamy oil flow would generate a foamy oil zone which re-saturated part of the solvent chamber. On the basis of this a phenomenon, this paper proposes a new way to enhance the CSI performance through a three-step pressure control scheme during the production period: first, reduce the model pressure to induce foamy oil flow and foamy oil zone; second, re-increase the model pressure to a preset value; third, maintain a certain pressure difference between injector and producer for gas flooding. This three-step process is called one pressure pulse and it can be consecutively repeated several times during the production period.
A series of laboratory experiments have been conducted with a visual rectangular sand-packed physical model. The sandpack permeability is ∼5 Darcy. Propane is used to recover a heavy oil sample with a viscosity of 5,875 cP. Results show that (1) foamy oil could effectively re-saturate the solvent chamber; (2) more pressure pulses would lead to more oil production, while the oil production decreases with pulse number in one cycle; (3) the oil production rate of PP-CSI is 4.37 times of that of conventional CSI, and the final recovery factor of PP-CSI is 17.9% higher than that of CSI. (4) flooding-induced viscous fingering can accelerate the mass-transfer rate; meanwhile, the viscous fingering will not cause an early breakthrough of the solvent chamber.
Seismic Anisotropy Characterization in Heterogeneous Formations Using Borehole Sonic Data
Authors: Jocker Jeroen , Ferla Maurizio , Pampuri Ferdinanda , Wielemaker Erik 
Published: September 2013

Abstract
Inverting borehole sonic data for anisotropic elastic parameters requires data acquired in, at least, two different orientations. In practice this often means combining acquisitions from two offset wells, which is only straightforward if the encountered formations are laterally continuous. If wells do not tie laterally, or if data acquired at different depths in vertically heterogeneous strata need to be combined, then an inversion strategy is required that explicitly takes heterogeneity into account.
This short note outlines such a strategy on the basis of borehole sonic and conventional petrophysical data, structural information, and well surveys. A new and sophisticated workflow was developed to estimate TI anisotropic parameters from borehole sonic logs, adopting a smart data clustering approach. Among other things, the output consists of elastic properties as a function of independently acquired data such as shale volume and density. In turn, these expressions constitute a model that is driven by measurements instead of assumptions, that can be established also in the presence of lateral and vertical heterogeneity, and that can be applied in neighboring wells where the amount of sonic data are insufficient for a complete inversion.
Standards for Characterization of Rock Properties in Unconventional Reservoirs: Fluid Flow Mechanism, Quality Control, and Uncertainties
Authors: Bertoncello A. , Honarpour M. M. 
Published: September 2013

Abstract
Estimating basic properties of unconventional shale reservoirs—such as permeability and porosity—is critical for reservoir evaluation, formation damage prediction, hydraulic fracture design, and performance forecasting. Several techniques can be used to measure these properties. For instance, the Gas Research Institute (Luffel et al. 1993) uses crushed rock, modeling high-resolution images of micron-sized samples, pulse decay, steady-state techniques to evaluate the permeability, and gas expansion and mercury immersion for porosity of a shale sample. However, the accuracy and reliability of these techniques are not well-established for unconventional reservoir rocks because of concerns about the flow regime, the absence of net confining stress, the sample size, and the imaging technique resolution.
This paper presents the results of a round robin permeability and porosity measurement performed at several commercial and research laboratories. The permeabilities of the evaluated samples vary from 10 nanodarcy to 10 microdarcy, and their porosities vary from 5 to 10%.
A wide range of natural and synthetic material was computed tomography (CT) scanned and microscopically examined. Selected samples were used based on their suitability for the desired range of porosity and permeability. The samples were examined before and after drying in a vacuum oven and then tested under several stress cycles. Gas permeability was measured by use of steady-state, transient pulse decay techniques and derived from mercury injection data. Porosity was measured by use of the gas expansion technique and mercury immersion. Image analysis of focused ion beam-scanning electron microscope (FIB-SEM) was also used to model permeability. Klinkenberg permeability was derived from apparent permeability by use of a range of mean pressures to examine validity of the Darcy flow regime.
The results of the round robin testing of porosity and permeability indicate:
Darcy flow is the predominant flow regime in shales with permeability as low as 10 nano-darcy, based on Klinkenberg characteristics and flow rate-pressure drop criteria. Permeability measurement on 10 nano-darcy to 10 micro-darcy permeability core plugs, under 400 to 5000 psi, is feasible and repeatable with a reasonable uncertainty range, at qualified commercial laboratories. Porosity data showed uncertainties in the range of ±1.0 p.u. for the natural samples. Steady-state method provides similar results from different laboratories, as long as an identical procedure is implemented. Uncertainty in steady-state permeability data from different laboratories could be as high as ±150%. Liquid permeability testing by use of supercritical fluid or laboratory fluid (Decalin) provides a complementary and valuable piece of datum. Rotary sidewall core plugs may provide higher quality core standards for shale material testing because the core plugging takes place under reservoir temperature and stress conditions.
Modifying Van Der Waals Equation of State to Consider Influence of Confinement on Phase Behavior
Authors: Ma Yixin , Jin Luchao , Jamili Ahmad 
Published: September 2013

Abstract
Phase behavior and fluid properties in porous media are governed by not only fluid molecule-fluid molecule interactions but also fluid molecule-pore wall interactions. The current available equations of state consider only fluid molecule-fluid molecule interactions and neglect the interactions between the reservoir fluid molecules and the solid wall of the porous media. For conventional reservoirs, this assumption may be valid because the formation pore sizes are much larger than molecular mean free paths. However, in shale formations that are characterized by nanopores, the fluid molecule-pore wall interactions play such an important role that can change phase behavior and crticial properties of the reservoir fluids. Consequently, the critical temperatures and pressures of multi-component hydrocarbon mixtures under nanopores confinement are influenced strongly by fluid molecule-pore wall interactions.
This work investigates the effect of pore proximity in tight and shale formations on phase behavior and fluid properties of the reservoir fluids by modifying van der Waals equation of state. Effects of both fluid molecule-fluid molecule and fluid molecule-pore wall interactions are included in the newly proposed equation of state. Based on molecular simulation studies, correlations are developed to consider the effect of fluid molecule-pore wall interactions for each component required for phase equilibria calculations under nanopore confinement using the proposed equation of state.
Phase behavior calculations of a mixture of methane, n-butane and n-octane were studied under confinement effects for pore sizes ranging from 10 to 2 nm. In general, with the decrease of pore size, the two-phase region of the fluid mixture tends to shrink, which makes the fluid mixture behave more like a dry gas. The results indicate that bubble point and dew point pressures of the confined fluids are up to 150 psi and 300 psi higher than their correspondent bulk values. Also n-butane and n-octane tend to evaporate more when pore size dereases.
The confinement effects can cause the fluid mixture to behave similar to dry gas, which results in reduction in condensate banking and less near-wellbore permeability impairment in comparison to conventional reservoirs. This has several implications for reservoir and well performances. One is that we can observe increased gas rates and enhanced recoveries over the life of the field by modeling these effects in a numerical reservoir simulation package.
Use of Co-Solvents to Improve Alkaline-Polymer Flooding
Authors: Fortenberry Robert P. , Kim Do Hoon , Nizamidin Nabijan , Stephanie S. Adkins , Pinnawala Arachchilage Gayani W. , Koh Heesong , Weerasooriya Upali , Pope Gary A. 
Published: September 2013

Abstract
We have found that the addition of low concentrations of certain inexpensive light co-solvents to alkaline-polymer solutions dramatically improves the performance of alkaline-polymer (AP) corefloods in two important ways. Firstly, addition of co-solvent promotes the formation of low viscosity microemulsions rather than viscous macroemulsions. Secondly, these light co-solvents greatly improve the phase behavior in a way that can be tailored to a particular oil, temperature and salinity. This new chemical EOR technology uses polymer for mobility control and has been termed Alkali-Co-solvent-Polymer (ACP) flooding. ACP corefloods perform as well as ASP corefloods while being simpler and more robust. We report 12 successful ACP corefloods using four different crude oils ranging from 12 to 24 °API. The ACP process shows special promise for heavy oils, which tend to have large fractions of soap-forming acidic components, but is applicable across a wide range of oil gravity.
Delivering Key WITSML Measured and Interpreted Well Information Through RESQML V2 for Reservoir Characterization and Flow Simulation
Authors: Henri-Bally Raphaele C. , Rainaud Jean-François , Deny Laurent , Legg Chris A. , King Michael J. , Verney Philippe , Schey Jana 
Published: September 2013

Abstract
It is now possible to integrate WITSML rig-issued well data, such as trajectory and associated raw measurements, and well analysis results stored in other data formats, including PPDM, into the RESQML set of data-objects that comprise the description of a reservoir or "Earth Model". It is now also possible to update the model as it is refined, through the life of a field.
To develop this integration, the RESQML and WITSML Special Interest Groups (SIG) of Energistics formed a Wells sub-group for the current RESQML version 2 (V2) development cycle. The sub-group is focusing on using the current WITSML V1.4.1.1 data model to abstract a simplified WITSML well consisting of three fundamental objects: its trajectory, either in depth and/or in time; a"WellboreFrame", which is used to reference the WITSML log data; and its extension to reference WITSML marker data. These objects reference WITSML but now exist in the RESQML data model, which allows them to access existing RESQML capabilities. Through this unified vision, the RESQML V2 data standard will allow drillers and production engineers to seamlessly access reservoir characterization and simulation results, and allow the reservoir engineers to benefit from the entire range of well-based drilling, petrophysical, and production data within an integrated team.
This paper presents how the RESQML V2 design allows association of WITSML and RESQML dedicated objects, and how to establish the relationships between these new objects and the structural, stratigraphic, and reservoir elements inside a RESQML model. In part, this integration has been enabled by the new Energistics Open Packaging Conventions (EPC), which allows multiple data standards (not only RESQML and WITSML) to be recognized and managed consistently.
This integration provides the foundation for future RESQML work, including plans to integrate the WITSML Completion data-object, and seismic data (represented in either time or space), both in the reservoir and at the wells.
Integration of Static and Dynamic Data for Enhanced Reservoir Characterization, Geological Modeling and Well Performance Studies
Authors: Ma S. M. , Zeybek M. , Kuchuk F. J. 
Published: September 2013

Abstract
A new methodology is presented for reservoir characterization, geological modeling, and well performance prediction by integrating a complete suite of petrophysical and pressure transient test data to build a detailed geological reservoir model with anisotropy. Data used includes cores, openhole logs, wireline formation tester (WFT) pretests, and vertical interference tests (VIT), production logs, and downhole pressure buildup and injection falloff tests. Core data is first integrated with openhole logs and WFT pretests to build a detailed geological model. Vertical and horizontal permeabilities derived from the VITs were then integrated to have a geological model with anisotropy. With the model, a single-well numerical pressure transient analysis was performed by simultaneously history matching the packer and the probe pressures as well as pressure derivatives to identify the presence of tight reservoir streaks and quantify reservoir layer permeability ranges. The model is further refined and validated by comparing with dynamic data derived from production logs and downhole pressure build-up and injection fall off tests. This validated reservoir model was used in single well reservoir simulation studies to predict well performance and inferring insitu reservoir scale reservoir condition petrophysical properties such as relative permeability and capillary pressure.
Mapping CO2 in Real Time in Hydrocarbon Reservoirs with Downhole Fluid Analysis: First Successful Experience in the East Irish Sea, UK Continental Shelf
Authors: Quayle B. , James S. , Quine M. , De Santo I. , Jeffreys P. , Y. Zuo Julian 
Published: September 2013

Abstract
This paper describes the first successful attempt in the UK Continental Shelf (UKCS) to map CO2 in real time while logging during Centrica's recently concluded four well drilling campaign in the East Irish Sea, offshore north-west England. The East Irish Sea basin is characterised by a range of source rock types, prolonged history of hydrocarbon generation, and Tertiary igneous intrusion. As a result, reservoirs contain varying proportions of carbon dioxide (CO2), nitrogen (N2), and hydrogen sulfide (H2S) in addition to oil and methane. Two of these wells will develop the Rhyl gas field that was discovered in 2009 and found to contain high concentration of methane and CO2 and some N2. An early and accurate understanding of gas composition and variation in such newly discovered fields is critical to reserves estimates, and scheduling and optimizing gas processing at the onshore North Morecambe Terminal.
CO2 had been recognised as a risk prior to drilling the Rhyl exploration well due to the relatively low CO2 content in the neighboring North Morecambe field. During logging and testing several qualitative indications of a higher CO2 content were identified: a high gas density measured at the separator and difficulty in sustaining a flare. Traditionally, the presence of CO2 has been assessed and quantified via lab analysis on samples acquired by both wireline formation testing tools and well tests. Reliable quantification of CO2 from reservoir fluid samples can be difficult due to mud filtrate contamination and because it readily dissolves in produced formation water.
In many CO2 rich reservoirs, compositional gradients are observed with higher CO2 concentrations at the base of the gas column. The two Rhyl development wells provide an opportunity to improve our understanding of the CO2 distribution throughout the field. The latest generation of Downhole Fluid Analysis (DFA) technologies was deployed with the Wireline Formation Testing (WFT) tool. Such technology uses a dual spectrometer system (filter and grating) to accurately measure CO2 content downhole, prior to scavenging. A dedicated channel for the CO2 absorption peak is complemented with dual baseline channels on either side to subtract the overlapping spectrum of hydrocarbon and small amounts of water. The DFA sensor was used at each sampling station during the WFT run of the first Rhyl development well measuring an almost constant vertical CO2 distribution. DFA data was complemented by pressure and pressure gradient analysis and integrated with high definition fullbore microresistivity images, allowing a better understanding of the gas composition across the Rhyl field, hence removing a significant project risk.