bluuebunny/crossref_metadata_2025_split huggingface dataset:
Best Practices for Obtaining Representative Formation Water Samples Using Formation Testers
Authors: Kim I. , Ramaswami S. R. , den Heuvel M. Mooijer-van , Koot W. , Cornelisse P. M. , Elshahawi H. 
Published: September 2016

Abstract
In the increasingly complex and challenging environments that oil and gas developments have to contend with, understanding of fluid properties is essential in optimizing the concepts that are ultimately used in development. The collection and analysis of downhole hydrocarbon samples have been given top priority, with the associated uncertainties having been dealt with adequately. By contrast, early assessment of formation water properties, has not always received the same level of attention with the reduction of the associated uncertainties generally not as robust.
This paper discusses the primary water properties and their impact on field developments. We discuss why it is critical that formation water samples are truly representative of the actual in-situ formation water properties. We then examine the two biggest challenges for formation tester sampling: mud contamination and inadequate conditioning/handling of the samples, particularly in wells drilled with water based mud (WBM). Finally, a case study is presented including the use of a miscible water tracer as well as the use of focused-sampling to obtain water samples with ultra-low mud contamination to emphasize the importance of obtaining reliable decontaminated formation water properties.
Application of Multi-Well Pressure Pulse-Code Testing for 3D Model Calibration
Authors: Aslanyan A. , Aslanyan I. , Farakhova R. 
Published: September 2016

Abstract
The paper describes advanced inter-well pressure interference testing used for 3D model calibration accounting for formation layering and rock compressibility in a mature Siberian waterflood field.
The new interference test is based on pulse-code testing (PCT) and can scan inter-well zones without a longterm production shutdown, normally required for conventional pressure interference testing (PIT).
There are numerous applications of this technique but this paper shows only two of them: Calibration of a geological model with respect to shale breaks by determining effective formation thickness by PCT and then its correlation with a production flow profile determined by Spectral Noise Logging and temperature modellingDetermination of rock compressibility distribution throughout a 3D simulation grid by estimating formation compressibility from PCT and correlating it with formation porosity from open-hole logs
The importance of compressibility calibration cannot be overestimated because it defines the formation pressure response to the non-compensated or over-compensated withdrawals across the field and different pay zones.
Conventional PIT can assess formation transmissibility and hydraulic diffusivity between wells. These two properties can be further converted to some basic 3D model inputs, for example effective formation thickness and compressibility, if permeability, SCAL, PVT and formation saturation are known. The main limitation of the conventional PIT is that it requires a receiving well to be shut-in to avoid contamination from production and that the pressure signal should not be contaminated by interference with other wells except the selected pulsing one. This limitation makes conventional PIT impractical for quantitative reservoir characterisation.
PCT generates coded flow-rate pulses in one well and provides a mathematical technique to decode a pressure signal in receiving wells into components from each pulsing well. This allows running PCT in multiple working wells with pre-set rate variation without shutting down production and assessing several inter-well intervals in parallel. A one-month PCT described in this paper resulted in 5% production loss, while conventional PIT would need three months with 60% production loss and a high risk of failure due to pressure contamination from remote processes.
Pushing the Completion Design Envelope in Ultra-Deepwater - Design, Installation, and Performance of Deep High Pressure Completions - A Case History of the Gunflint Development, Offshore Gulf of Mexico
Authors: Sanford Jack , Healy John , Hopper Tim , Fink Josh , Grammer Ladd , Koy James , Perroux Jocelyn , Magin Ian , Williams Kevin , Seeley Tom 
Published: September 2016

Abstract
A Gulf of Mexico case history is presented that describes the successful delivery of two (2) deep (27,000-ft) high pressure (&gt;17,500-psi) high rate design (25,000 BOPD) oil wells in an ultra-deep water (+6000-ft) environment. Well conditions, coupled with challenging production requirements (depletion of 10,000-psi), provided a very arduous design challenge. One well was completed as a single frac pack at 27,000-ft MD. The second well required a stacked frac pack at 25,000 ft-MD and intelligent flow controls.
Twenty-seven (27) firsts, to the industry and / or Noble, were required to deliver the final completion designs. These firsts ranged, to name a few, from a new tieback casing material, a paradigm change in the Temporary Abandonment (TA) procedure (which yielded a cost savings of $15 million per well), a new perforating charge, qualification of a new material for the Gravel Pack (GP) packer, weighted frac fluids, changes in the upper completion designs, Vacuum Insulated Tubing (VIT) welding qualification and re-design of a control line Y-block. Any one item or any single technology gap, is seldom insurmountable. However, it is the layers and the multitude of challenges in these type of environments, where every component and their interdependencies are stretched to the edge of the design envelope that pushes the completion team and suppliers to their limit. All of these together make the goal of flawless execution very challenging. This paper will provide an overview from design thru operations, and highlight some of the engineering challenges and lessons learned.
A field proven completion delivery process combined with a team of experienced people and rigorous procedures successfully designed and delivered two (2) complex completions that were on the edge of deep-water completion technology. Based on the Rushmore Review database, both wells (1 single GP and 1 single selective GP) were the fastest completions (when analyzed on a well depth basis) since Macondo. Both wells were completed in 2015, and are currently waiting on final hook-up and commissioning. First oil is forecast for July 2016.
Industry will continue to explore ultra-deep water and discover deeper and higher pressure reservoirs that push the completion technology envelope. It is imperative that engineers be able to confidently design and deliver completions for this extreme environment that will achieve the productivity and reliability required by the project economics. The aim of this case history is to provide the engineer, faced with similar challenges, with information that may prove beneficial in the approach, method, design and delivery of these type of complex, critical completions.
Petrophysical Study of UAE Carbonate Outcrop at Jabal Hafit
Authors: Sondergeld Carl H. , Wampler Jeff , Abdelghany Osman , Anin Al , Rai Chandra , Curtis Mark 
Published: September 2016

Abstract
Jabal Hafit consists of Tertiary outcrops that give insight into stratigraphic sequences and regional reservoirs in the Middle East. This study examines outcrops from various strata in the Rus, Dammam, and Asmari Formations varying from Early Oligocene to Eocene in age. These Formations exist throughout the UAE and Middle East and contain some large regional hydrocarbon reservoirs.
This study examines porosity, permeability, mineralogy, NMR, MICP (mercury injection capillary pressure), and SEM images for 72 core samples. FTIR (Fourier Transform Infrared) mineralogy shows that these samples are calcite dominated carbonates with two strata being dolomite dominated. Sample porosities decrease linearly with increasing pressure and range from 0.47 to 27.26%. Klinkenberg permeabilities decrease linearly with increasing pressure for most samples, with some samples showing nonlinear pressure dependence indicating the presence of cracks. Permeabilities range from 0.0002 to 54.85 md. A porosity-permeability correlation has been developed based on measured core data. The Reservoir Quality Index is used to identify similar reservoir flow characteristics and two flow zones have been identified across the three Formations. The second flow zone demonstrates some permeability pressure dependence. NMR shows bimodal pore distributions in some samples as well as extreme variability from layer to layer. A comparison of NMR, ϕNMR, and Boyle's Law, ϕHe, porosities shows good agreement at porosity values lower than 10% with the ϕNMR &lt; ϕHe at larger porosities. The Free Fluid Model and Mean T2 Model are used to estimate permeability from NMR data. Corrected T2 cutoffs are determined from Swir via centrifuge method to define the correct Bound Volume Irreducible (BVI) and Free Fluid Index (FFI) for each sample. Measured T2 cutoff times range from 2.38 to 598 ms. Calibrated and uncalibrated Free Fluid Model and Mean T2 Model permeabilities are compared with measured core permeability values. For these samples, the Mean T2 Model gives a better permeability estimate. SEM images reveal the bulk of the pores are equant in shape and document the existence of microporosity. Some MICP and NMR measurement capture the bimodal pore distributions.
Experimental Study of Gas-Liquid-Coal Fines Three-Phase Flow in Undulating Horizontal Wellbore
Authors: Han Guoqing , Pan Zhejun , Zhang He , Ling Kegang , Teodoriu Catalin 
Published: September 2016

Abstract
In Coalbed Methane (CBM) reservoir, especially the thin low permeability CBM reservoirs, undulating horizontal wells are often drilled to maximize contact area with the reservoir for higher CBM production rates. Coal fines, however, may accumulate in the wellbore, making pressure along the wellbore trajectory more complex, affecting gas production behavior. This paper presents experimental work to study the coal fines-water-gas three-phase flow in transparent pipes to mimic different undulation angles that may occur in horizontal wells. Coal fines with different particle sizes are studied. Observed from the experiments, four flow patterns for coal fines migration were identified: stratification, saltation, moving dunes, and dispersed flow. Moreover, relations between coal fines critical moving velocity and discharge velocity and the size of coal fines are investigated. This paper further investigated the settlement and plugging of coal fines at the curvature section of the pipes under four flow regimes: elongated bubble, transition, slug, and intermittent flows. Using the experimental data, we estimated the boundaries for five flow regimes under five different undulation angles. The analyses indicated that the pressure fluctuation magnitude increases when flow regime evolves from bubble flow to intermittent flow. The largest pressure fluctuation and the lowest fluctuation frequency take place under intermittent flow. Based on the experimental data, this paper derived the critical velocity correlation for coal fines in undulating CBM wellbore. The findings of this study is useful for CBM development in the field, which may help to optimize wellbore geometry to minimize coal fine settlement/plugging, act as a guide in designing well flushing operation to effectively circulate coal fines out of bottomhole.
Selection of Geologic Models Based on Pareto-Optimality Using Surface Deformation and CO2 Injection Data for the in Salah Gas Sequestration Project
Authors: Min Baehyun , Nwachukwu Azor , Srinivasan Sanjay , Wheeler Mary F. 
Published: September 2016

Abstract
A model selection process based on multi-objective optimization using a fast proxy is presented that chooses geologic models conditioned to observed flow and geomechanical responses. The responses of geologic models to injection of large volumes of CO2 are evaluated using a proxy that approximates pressure distribution using a random walk particle tracking algorithm and computes surface deformation using a stress-field solver. The geologic models showing similar proxy responses are grouped into clusters by invoking multi-dimensional scaling and k-means clustering. A representative model of each cluster is chosen and its simulation results are compared to the observation. The resultant posterior ensemble consists of models that belong to one or more clusters whose representative models are not only in good agreement with given observation data but also non-dominated to other representative models. The usefulness of the model selection approach is demonstrated on CO2 sequestration of a fractured gas reservoir at In Salah, Central Algeria. The explicit coupling of the connectivity estimator and the stress solver reproduces similar migration patterns of CO2 plume to those obtained using full-physics numerical simulations. Incorporating time-lapse observations measured using satellite-based interferometric synthetic aperture radar imposes additional constraints to refine geologic models by improving the matching quality of bottomhole pressure, and thereby contributes to a further reduction in geologic uncertainty. The multi-objective optimization process implemented in the model selection process yields a diversified model set than those obtained using a global optimization procedure. The posterior ensemble exhibits consistent geologic characteristics in terms of spatial distribution and orientation of migration pathways. The posterior ensemble is then used as an initial population for a multi-objective history matching procedure. The results of model selection and expansion process indicate that the implementation of Pareto-optimality is advantageous to realize diversified geologic models that yield unbiased assessment of uncertainty associated with prediction of future CO2 plume migration.
Quantification of Directional Pore Network Connectivity and Rock Fabric and its Application in Enhanced Assessment of Hydrocarbon Reserves
Authors: Garcia Artur Posenato , Heidari Zoya 
Published: September 2016

Abstract
Success of the strategies to exploit hydrocarbon reservoirs depends on the availability of reliable information about pore structure and spatial distribution of fluids within the pore network. Reliable quantification of directional pore network connectivity and characterization of pore architecture is, however, challenging. The objectives of this paper include (a) quantifying the directional connectivity of pore network and rock components, (b) investigating the consistency of the estimated directional connectivity at a given rock type in the formation, (c) identifying geometry-defined fabric features that cause the connectivity variations within the same formation, and (d) improving assessment of hydrocarbon saturation using the introduced quantitative directional pore-network connectivity factor.
We introduce a new directional pore-network connectivity factor to quantify rock fabric. In order to evaluate its consistency in pore- and log-scale domains in the same rock types, the first step includes rock classification based on well logs and well-log-based estimates of petrophysical/compositional properties. Then rock samples from each rock type are scanned using a micro-Computed Tomography (CT) scanner, processed, and digitized into pore and grain regions. Afterwards, the pore-network connectivity of the three-dimensional (3D) pore-scale images are obtained using a semianalytical streamline algorithm. The geometrical features are quantitatively evaluated from these images and combined with the estimated connectivity. The new quantitative connectivity factor is finally used to improve evaluation of electrical resistivity logs for assessment of hydrocarbon saturation.
We successfully applied the introduced method to a carbonate formation. The results confirmed that the introduced directional connectivity factor can detect rock fabric features and is a function of the directional diffusivity coefficient. This parameter remains persistent in the same rock type in the formation, which enables a reliable and enhanced interpretation of electrical resistivity logs in formations with complex pore structure. The quantification of rock fabric and pore network connectivity improved the estimation of hydrocarbon saturation by up to 61% when compared to conventional methods. The use of such parameter for rock fabric characterization minimizes the need for calibration efforts in interpretation of borehole geophysical measurements. Few cuttings from different rock types are sufficient for the proposed method.
Describing and Modeling Saturation Versus Height in Fields With Immobile Hydrocarbons Below the Contact
Authors: Pentland Christopher H. , Yarabi Mohamed K. , Boya Ferrero Maria J. , Svec Robert K. 
Published: September 2016

Abstract
We investigate the relationship between saturation and height in fields where oil or gas is present below current day free water level. Such situations arise in a number of fields in Oman with complex charge, structural and regional hydrodynamic history. The change in saturation with height – and importantly whether intervals contain mobile or immobile hydrocarbons – is a key parameter influencing volumetrics and field performance.
The correct identification and interpretation of this phenomenon is hindered by the inability to reconcile core-based saturation-height relationships with field observations including saturation from logs. This difficulty arises as core-based saturation-height modeling traditionally only considers the primary drainage (hydrocarbon displacing water) flow sequence. We present a simple analytical model incorporating both core-based primary drainage and imbibition (water displacing hydrocarbon) flow sequences which is able to describe the complex saturation scenarios discussed. The model has been validated against numerical simulations, can handle multiple rock types and is easily coded in a spreadsheet.
We compare our simple core-based model with log observations from example fields. The model can replicate observed saturation profiles within measurement uncertainty including the mobile hydrocarbon saturation above the current free water level as well as the immobile hydrocarbon saturation below. The implications for correct log and core data gathering and interpretation are summarized and the impact on field performance is discussed.
The work highlights the important role the imbibition flow sequence can play in describing hydrocarbon saturation changes with height in some fields: this is often overlooked yet critical for the correct description of some fields. Model inputs require imbibition experiments to be considered in data gathering campaigns.
A companion paper published in parallel discusses the processes that affect fluid distributions and outlines recommended diagnostic tools and workflows (Boya Ferrero et al., 2016).
Reservoir Characterization Using Fuzzy Kriging and Deep Learning Neural Networks
Authors: Korjani M. M. , Popa A. S. , Grijalva E. , Cassidy S. , Ershaghi I. 
Published: September 2016

Abstract
The sandy-clayed heavy oil hydrocarbon reservoirs of the Miocene formations in San Joaquin Valley, California, present relatively high complex geologic settings. These reservoirs consist in general of sandstone, silts and shale bodies, and present anywhere from six to eight degrees of inclination. Geostatistical tools were used to characterize the reservoir and develop a full earth model for the field. The data used was mainly based on the suite of resistivity logs (shallow, medium and deep), which seems to best represent the formations, while a classic kriging technique was used for modeling.
In the present research, we introduce a new approach for characterization of these heavy-oil reservoirs by using fuzzy kriging and deep learning neural networks. The new model better captures the uncertainty associated with the characteristics of the reservoirs. Once successfully trained, the system was applied to generate a 3D earth model and estimate reservoir properties at any point in the field. The new earth model successfully improves the resolution and realization of the subsurface model, as compared to the existing one developed using classic kriging. Integrating fuzzy kriging solves the limitation of smoothness of kriging estimation and reproduction of extreme values. Additional capability includes generation of synthetic logs for wells anywhere in the reservoir, with a significant application for infill drilling.
The methodology presented in this research proved to be very successful as developed for modeling alluvial deposits such as the heavy oil reservoirs in San Joaquin Valley, California. Further research should be considered to address other geologies where laterally formations vary in characteristics or where pinch outs or faulting occur.
Solids Production Prediction and Management for Oil Producers in Highly Depleted Reservoirs in a Mature Malaysian Field
Authors: Asadi M. S. , Khaksar A. , Ring M. J. , Saric D. , Yin Yin M. 
Published: September 2016

Abstract
This paper presents a case study of a geomechanical evaluation used in sand management decisions in a mature oil field offshore Malaysia. Elements of a field-wide geomechanical model were constrained from various data types from a vast number of wells drilled in 1980s and new re-development wells drilled in 2013–15. Extensive production from multilayer stacked reservoirs has resulted in large pressure depletion; hence drilling of infill wells and water injection is used to enhance oil production in the field.
A poroelastic analytical sand production prediction approach was used to investigate the risk of sanding in both existing and new wells under high depletion conditions. Historical production data were used to calibrate and verify the sand production predictions. The analysis also included rock mechanics laboratory experiments on core samples saturated with mineral oil and brine to characterize the amount of rock weakening in the presence of water, which showed target sandstones may weaken by 13–16% when they are exposed to brine compared to the mineral oil saturated condition.
The results showed a very low risk of sanding for the target oil reservoirs over the field life, using expected final reservoir pressures of 100 psi for cased and perforated completions drilled in any direction. The risk of sanding for open holes, however, was found to be slightly higher with further depletion from the current reservoir pressures, particularly with the likely rock weakening effect under water production and injection conditions. Moreover, hole instability and solids production resulting from the failure of the shale interbeds under low downhole pressures and water production could be a well integrity risk, jeopardizing production in open hole completions.
The sand production prediction model is used to identify the optimum completion strategy in new wells considering the strength of target reservoir rock, well trajectory, and reservoir pressure and production conditions on a well by well basis. For most planned wells, cased hole completions with oriented and selective perforations appeared adequate to mitigate the sanding risks in both production wells and water injectors. Sand-free production to date from recently-drilled cased and perforated infill wells confirms the accuracy of the pre-drill sanding evaluation and sand management decisions.