bluuebunny/crossref_metadata_2025 huggingface dataset:
The Methods of Correcting NMR Data from Dry Gas Wells Drilled with Formate Based Muds by Advanced NMR Techniques
Authors: Kwak Hyung T. , Hursan Gabor , Gao Jun , Harbi Ahmad , Ma Shouxiang
Published: June 2017

Formate-based drilling mud is used to improve the performance of drilling and completions of high pressure and high temperature (HPHT) wells due to its properties such as high density (up to 19 lbs/gal), non-corrosiveness, eco-friendliness, high stability, and miscibility with brine and other fluids in the drilling muds. However, these strengths of formate muds pose challenges for formation evaluation due to their unusual properties such as high density, low Hydrogen Index (HI), miscibility with connate brines, and high conductivity.

The current work addresses challenges of Nuclear Magnetic Resonance (NMR) logging, which is known to provide capillary bound fluid for producibility evaluation and accurate porosity for reserve estimation, in deep dry gas wells drilled with formate mud. With a carefully designed workflow composed of a suit of laboratory NMR techniques, the needs for the correction of T2cutoff and HI by Formate Mud Filtrate (FMF) invasion have been investigated. To quantify the accurate amount of correction required, FMF invasion has been monitored under reservoir conditions. The experimentally determined NMR T2 cutoff values for FMF saturated samples are always slightly longer than those for brine saturated ones. The difference of bulk volume movable (BVM), however, is less than 5% when T2 cutoff value from brine saturated sample is applied to FMF saturated sample. Thus, T2 cutoff determined by conventional NMR laboratory measurement with brine can be applied to NMR log with the formation invaded by FMF.

The HI correction factors for BVM and bulk volume irreducible (BVI) are dependent on pore structures. For brine saturated bi-modal sandstones, all pores are displaced by FMF which corresponds to an HI correction factor of 0.74 for both BVM and BVI. For brine saturated carbonate with tri-modal pore system, however, 100% BVM and 70% of BVI have been displaced with FMF which correspond to HI correction factor of 0.78 and 0.80 for the FMF used in the current study, respectively.

The outcome of the current study will help to enhance the usage of NMR logging as powerful formation evaluation tool for gas wells drilled with formate based drilling muds.
Experimental Investigation and Optimization of Polymer Enhanced CO2 Foam Stability and Apparent Viscosity
Authors: Ahmed Shehzad , Elraies Khaled Abdalla , Hashmet Muhammad Rehan , Bt Mohd Shaifan Siti Rohaida , Hsia Ivy Chai , Bahrim Ridhwan Zhafri
Published: June 2017

Polymer enhanced foam (PEF) provides an additional strength over conventional CO2 foams for mobilizing oil from the unswept low permeable oil rich zones during an enhanced oil recovery process. The efficiency of the process depends on two major factors i.e. stability and apparent viscosity of PEF. In this study, an experimental investigation of apparent viscosity and stability of polymer enhanced CO2 foam is presented with an objective to assess the polymer performance and to identify the best performing polymer under reservoir conditions of 1500 psi and 80 °C.

For this purpose, conventional standard hydrolyzed polymacrylamide (HPAM) polymers and an associative polymer i.e. Superpusher P329 were used in combination with a widely used foamer i.e. alpha olefin sulfonate (AOS) and a foam stabilizer i.e. betaine. Foam stability tests were conducted in the presence of crude oil using FoamScan. Whereas for foam rheological study, a high pressure high temperature Foam Rheometer was utilized and the foam was sheared over the range of 10 to 500 sec−1 inside the recirculating loop.

As compared to other HPAMs, an associative polymer i.e. Superpusher P329 significantly amplified foam longevity and provided a more prolonged liquid drainage. A shear thinning behavior was observed for the entire range of shear rate tested and for all the tested foam. HPAMs were found ineffective in improving foam apparent viscosity and the viscosities obtained were found equivalent to that to polymer free foam. Superpusher P329 showed interesting combination with AOS and significant viscosity enhancement has been reported in this paper.

This research concluded that Superpusher P329 has the ability to generate strong foam and it is a potiential candidate for mobility control during polymer enhanced CO2 foam flooding process. Keywords: Polymer Enhanced Foam, foam stability, apparent viscosity; CO2 foam.
Effective Solutions for Cementing Shallow Hazards in Saudi Arabian Fields
Authors: Bazuhair Mohammed , Shine Jr Joseph M , Al-Mutahr Ammar , Abdurrahman Riefky , Shafqat Ali , Mojbel Mohammed
Published: June 2017

Shallow hazard migration post-cementing is a well-known and costly problem worldwide. It is extremely difficult to fix once it has occurred since limited remedial options are available with marginal success rates. Its causes are easy to understand yet it needs careful planning to prevent it. Post-cementing shallow water flow and gas migration may occur due to several collective causes such as poor fluid displacement efficiencies, losses prior/post or during cement placement, and/or underperforming slurry properties.

Previously proposed solutions focus only on one of these challenges with various success rate depending on well conditions. Addressing all these challenges together is essential for successful prevention. Due to the nature of these wells containing the high probability of flow from these shallow hazards, the clearances between pore and fracture pressures are narrow. This makes the common mud removal approach of displacement mechanics challenging. It also requires a delicate balance between maintaining sufficient hydrostatic to remain above the pore pressure of the flow zone and losing to the weak formations. Independent of these boundary conditions, the slurry needs to have a given set of performance properties to prevent any influx into the annulus.

This paper discuss the successful implementation of cementing solutions and control measures used to prevent shallow hazards migration in Saudi Arabia. This manuscript will discuss the field implementation and operations documenting the step changes success.
A Novel Acid Transport Model with Robust Finite Element Discretization
Authors: Alhubail Mustafa M. , Misra Anil , Barati Reza
Published: June 2017

The purpose of designing an acid fracturing model is to examine the two factors that measure the effectiveness of the acid fracturing treatment. The two factors are the acid penetration distance and the fracture conductivity after closure stress is reached.

The acid fracturing model is designed by coupling a fracture propagation model and an acid transport model. The advanced fracture propagation models are developed numerically by the finite element method (FEM,) or the extended finite element method (XFEM.) However, the acid transport models that are reported in the literature are developed using the finite difference method (FDM.) The finite element method is a more stable and accurate technique to model the complex system of the acid transport along with fracture mechanics and heat transfer than FDM. Furthermore, FEM is a more powerful and suitable technique for meshing sophisticated geometries such as fractures. Thus, an acid transport model has been developed numerically using FEM.

The objective of developing this FEM model is to eliminate the need of using different mapping and coordinate transformation techniques for the fracture propagation model and the acid transport model; hence, diminishing the inaccuracy when meshing the geometry.

The developed FEM model has been validated against analytical and numerical models, and it has been verified that the algorithm is stable and robust. The developed model predicts accurate velocity and temperature profiles. In addition, the model can handle acids with non-Newtonian flow behavior at a specific acid viscosity and acid dissolving power. It has been found that acids with shear thinning flow behavior yields shorter acid penetration distance compared to acids that are behaving as a Newtonian fluid. Furthermore, the effect of wormholes on the acid distribution has been studied, and it has been found that high injection rates result in deeper wormholes.
Revised Experimental Approaches To Address Shale Drilling Challenges
Authors: Al-Arfaj Mohammed K. , Amanullah Md , Zaidi Syed , Sultan Abdullah S. , Abu-Khamsin Sidqi
Published: June 2017

Shale drilling problems are major sources of non-productive time in drilling operations. The use of water-based drilling fluids to drill shale formations can cause wellbore stability problems such as swelling, dispersion and heaving as a result of the reaction of water with clay minerals. Consequently, wellbore instability problems can be triggered and stuck pipe problems can be encountered due to tight spots or higher solids loading in the wellbore. Therefore, it is essential to have the required techniques to assess the shale samples and their adsorption and swelling potential in order to be proactive and mitigate the scope of shale drilling problems. Initial moisture content is one of the factors controlling the swelling behaviour of shales. Correlating the ultimate swelling percentage to moisture content and other parameters can help in predicting the swelling potential and mitigating any associated problems. It was found that swelling potential increases for shale/clay samples with higher moisture content. Furthermore, evaluation of the long-term inhibition potential of shale inhibitors is necessary to mitigate time dependent borehole instability problems. Due to the presence of some unique geological conditions as in the case of a loss circulation zone overlaid with a shale formation, sometimes there is a need to replace a high cost inhibitive mud with a low cost non-inhibitive mud to drill the next formation. If the original inhibition provided by the inhibitive drilling fluid to the shale rock does not last long enough to drill the loss circulation zone, the previously drilled shale formation starts reacting again with the non-inhibitive drilling fluid leading to various drilling problems. Hence, there is a need for isolation of the reactive shale zone by a casing string before drilling ahead. Inhibitive muds with long-term inhibition potential may eliminate the need of a protective casing for the previously drilled shale formation. Two shale inhibitors were tested: potassium chloride and polyamins. The results showed the superior performance of the polyamines as long-term shale inhibitors compared to potassium chloride especially with shale samples of high kaolinite content.
Effect of Mobility and Convection-Dominated Flow on Evaluation of Reservoir Dynamic Performance by Fast Marching Method
Authors: Al-Qasim Abdulaziz , Kelkar Mohan
Published: June 2017

The determination of optimum well locations and number of wells needed during green field development always comes with unprecedented challenges because of the geological uncertainty, and the non-linear relationship between the input and output variables associated with real reservoirs. These variables are key sources affecting the viability and validity of the results.

Reservoir simulation is one of the least uncertain and most reliable prediction tools for dynamic performance of any reservoir. As field development progresses, more information becomes available, enabling us to continually update and, if needed, correct the reservoir description. The simulator can then be used to perform a variety of exercises or scenarios, with the goal of optimizing field development and operation strategies. Optimizing well numbers or locations under such geological uncertainty is achieved by using a reservoir simulator under several geological realizations, and these require multiple reservoir simulations to estimate the field performance for a given well configuration at a given location.

Using reservoir simulation becomes impractical when dealing with real field cases incorporating multimillion cells because of the associated CPU demand constraints (Bouzarkouna et al., 2012). For instance, to determine the optimum well locations in a giant field that will result in the most efficient production rate scenario, one requires a large number of simulation runs for different realizations and well configurations. A large amount of runs is technically difficult to achieve even if we have access to super computers.

The Fast Marching Method (FMM), which is based on solution of Eikonal equation, can be used to find the optimum well locations in a green oil field by tracking the pressure distribution in the reservoir. The FMM will enable us to calculate the radius of investigation or pressure front as a function of time without running any simulation and with a high degree of accuracy under primary depletion conditions.

The main purpose of this paper is to study the effect of mobility on FMM and extend the investigation of its validity to include two phase-flow and convection-dominated flow and evaluate the ability of the methodology to predict the dynamic performance of the reservoir during pseudo-steady state flow regime.
Reservoir Description Insights from an Inter-well Chemical Tracer Test
Authors: Sanni Modiu , Abbad Mohammad , Kokal Sunil , Ali Razally , Zefzafy Ibrahim , Hartvig Sven , Huseby Olaf
Published: June 2017

Tracer technology has evolved significantly over the years and is being increasingly used as one of the effective tools in the reservoir monitoring and surveillance toolbox in the oil and gas industry. Tracer surveys, conducted either as inter-well tests or single-well tests, are one of the enabling technologies that can be deployed to investigate reservoir flow performance, reservoir connectivity, residual oil saturation and reservoir properties that control displacement processes, particularly in improved oil recovery (IOR) and enhanced oil recovery (EOR) operations.

As part of the comprehensive monitoring and surveillance program for an IOR injection pilot project in a Jurassic age reservoir, an inter-well chemical test (IWCTT) was designed and implemented to investigate reservoir connectivity between injector and producer well pairs, water breakthrough times ("time of flight"), and possible inter-well fluid saturations. Four unique tracers were injected into four individual injectors, respectively, and their elution were monitored in the four "paired" up-dip producers.

In addition to the reservoir connectivity and breakthrough times between the injector and producer pairs, the results showed different trends for different areas of the reservoir. A detailed analyses of the exit age distribution and residence time distribution (RTD) curves showed two peaks for three of the injector-producer pairs and a single peak for the last pair. These were reflective of some apparent reservoir heterogeneities that were not anticipated at the beginning of the pilot.

This paper reviews the complete design and implementation of the tracer test, field operational issues, analyses, and interpretation of the tracer results. The tracer data has been very useful in understanding well interconnectivity and dynamic fluid flow in this part of the field. This has led to better reservoir description and an improved dynamic simulation model.
Designing and Validating 2D Reservoir Models
Authors: Thompson Troy , Vogt Jay , Zaretskiy Yan
Published: June 2017

2D Conformal Modeling (2DCM) is a ground-breaking technique for building and maintaining 2D structural frameworks, especially with the existence of high-angle horizontal wells. 2DCM is proposed as the standard tool for accurately and efficiently interpreting horizontal wells and constructing frameworks. The 2DCM workflow has been developed and refined over the past 10 years using thousands of horizontal wells in active development areas across a wide region. In addition to accurately representing the geological observations along the entire horizontal well, it is a very efficient method that enables interpreters to update their models while drilling and to accurately incorporate intra-formational observations. This enables truly "living" models that serve as the front end to reservoir and fluid modeling, forming the basis of a Live Earth Model.
Unconfined Compressive Strength Prediction from Petrophysical Properties and Elemental Spectroscopy Using Support-Vector Regression
Authors: Negara Ardiansyah , Ali Syed , AlDhamen Ali , Kesserwan Hasan , Jin Guodong
Published: June 2017

Unconfined compressive strength (UCS) of rock is a key parameter in drilling and stimulation of oil and gas wells such as wellbore stability and fracturing operations. Better estimates of UCS could increase the efficiency of drilling and stimulation operations. Current techniques for UCS determination either rely on laboratory measurements or empirical relationships using well logs. The laboratory measurements, although more reliable, are expensive and time-consuming. On the other hand, the empirical relations derived from core data and well logs are very unique because they are developed for a specific rock type; hence has limited applications. This paper presents a data-driven model for UCS prediction from petrophysical properties and elemental spectroscopy using artificial intelligent technique, namely support-vector regression (SVR).

Elemental spectroscopy, density, porosity, and UCS data presented in this paper are based on various geological formations. UCS is determined by the uniaxial compression test in the laboratory, while elemental spectroscopy was obtained from X-ray fluorescence (XRF) analysis. We first use SVR to establish a correlation between elemental spectroscopy, density, and porosity with UCS. We separate these data into two categories: training and testing data. Training data is used to train SVR and establishes the UCS prediction model. The model will generate UCS prediction using testing data and compared with the laboratory-measured UCS.

In total, 21 cases were run with different combination of input parameters. Good agreement was observed between the SVR-predicted UCS and the laboratory measurement. Two quantitative measures for estimation accuracy are calculated and examined including the coefficient of determination and the mean absolute percentage error. Considering limited number of available data used in this study, the SVR-predicted UCS produces very good coefficient of determination and small error. The results also demonstrate the significant influence of elemental spectroscopy on the UCS prediction because elements determine grain density, which contributes to the rock strength. This emphasizes the advantage of incorporating elemental spectroscopy, together with other petrophysical properties, for UCS prediction. The favorable results in this study demonstrate the promising capability of SVR to build a UCS-prediction model based on elemental spectroscopy and petrophysical properties. Further application of SVR can be adapted to predict UCS directly from mineralogy logs and conventional well logs.
Fit for Purpose Design of High Performance Water Base Mud Successfully Replaced Oil Base Mud
Authors: Ferras Abdelkader , Al Obeidany Rashid , Qassabi Nabhan , AL Aghbari Salim , Abry Nadia , Benmesbah Mohamed Oukil , Benmahiddi Samir , Radwan Mohamed , Van Der Werff Niels , Samiee Rady Abdel , Mahrooqi Mohammed , Chibani Zied
Published: June 2017

Despite the associated waste management cost to comply with the international standards, Oil Base Mud (OBM) remains the drilling fluid of choice to drill trouble prone formations in PDO LLC, Oman drilling operations mainly through the formations of Fiqa Sharji, Nahr Umr, Khuf and Gharif in different fields of Oman. Low Toxicity Oil Base Mud (LTOBM) is exhibiting excellent well bore stability due to oil wet property, however, its high cost resulting from low aromatic base oil and associated waste management to comply with the international standards and local environmental regulations provided the impetus to conduct a feasibility study to identify an environmentally friendly and cost effective drilling fluid without impairing drilling performance. The evolvement of High Performance Water Base Mud (HPWBM) technology helped to identify a fit for purpose drilling fluid capable to deliver near OBM drilling performance with cost effective environmental compliance with local regulations.

The following tests were carried out on different cuttings samples collected from the aforementioned formations when exposed to different drilling fluids formulations:

Cation Exchange Capacity (CEC). Linear Swelling. Shale recovery. Accretion.

As a result of the intensive laboratory work, an appropriate HPWBM system was selected for each formation and each field. The first fields' trials concluded promising results with 100 % success rate on vertical wells and 50 % success rate on horizontal wells. HPWBM drilling performance was competing with OBM with significant cost reduction of 33-70 %. Further benefits, such as better zonal isolation achieved through better cement bonding to both formation and casing is worth considering.

More importantly, two wells drilled by this HPWBM were initially planned to be water injector wells and ended by being converted to oil producers after positive logging results. This is an important field proven feature for a reservoir friendly system.

This paper details the engineering works performed at PDO laboratory on testing the shaly cuttings behavior against different drilling fluids and at the field trials describing the best practices.
Introducing a Big Data System for Maintaining Well Data Quality and Integrity in a World of Heterogeneous Environment
Authors: Bin Mahfoodh Abdulelah , Ibrahim Mohamad , Hawi Maan , Hakami Khalid
Published: June 2017

Oil and gas industry is a data-driven industry as it depends massively on information technology. According to internal statistics, the amount of data coming from upstream alone is doubling every two years. This data arrives through a wide variety of vendors’ sources and is handled by various applications’ repositories. Well data, in specific, is a key asset for such industry throughout the process lifetime from early exploration to production. In practice, companies often tend to create their own well data master repositories that are poorly synchronized between each other and with other databases. This results into well data residing in silos databases with no commonly defined standard. Often, there is little mechanism to cross-validate well data quality across various sources. Thus, maintaining high quality level of definitive versions of well data is a critical activity to any firm's data management strategy.

Recently, Big Data technologies have evolved to quickly fetch and analyze large volumes of data that can substantially lead to an improved data quality at reasonable time. In this paper, a novel system is presented to preserve high level of well data quality in a heterogeneous environment. This system utilizes Apache Spark as a main framework for distributed processing and a mid-tier software as a data integration layer. Through a set of defined mapping rules, the system will compare data from multiple databases against the database that hosts the organizational verified data. It is typical for oil and gas companies to dedicate one master database containing the corporate standard well data. So, this database will be used as a source for comparison against well data residing in project repositories. Moreover, the system extends its functionality to cover well sub data types such as headers, check shots, deviation surveys, and picks. The final output is a data quality report that helps in making strategic decisions.
Optimizing Hydraulic Fracturing Design by Analyzing Reservoir, Completion, and Stimulation Parameters and their Influence on Post-Fracturing Gas Rates
Authors: Rahim Zillur , Al-Kanaan Adnan , Kayumov Rifat , Al-Jalal Ziad , Viswanathan Anup
Published: June 2017

With the increase in gas demand and the need to supply additional energy, the focus is now shifted to drilling and production activities exploiting high-pressure/high-temperature (HPHT) tight sandstone gas formations. The design optimization and selection of proper hydraulic fracturing technology is a key to succeeding in getting an economic gas production rate. Using well performance as the primary determining factor, a systematic study and evaluation was conducted on 20 vertical and horizontal wells drilled in HPHT heterogeneous sandstone reservoirs to assess effectiveness of stimulation treatments and benefits of using novel technologies. The numerous variables analyzed to determine the impact on production include different completion options, type of fracturing technology used, various proppant and fluids, fracturing method, production rate, and flowback parameters. A comprehensive database for stimulated wells was created that included reservoir parameters, completion data, minifrac and main stimulation treatment parameters (additives, fluid and proppant types, volumes, rates, and pressures), post-fracturing flowback results, and monthly production data. The production data were normalized on reservoir quality to strengthen the effect of fracturing parameters on well productivity independent of reservoir quality. Correlations were drawn using the Pearson correlation coefficient to compute the upward and downward data trends, ensure use of good quality data, and discard the few nonaligned data. Numerous very useful plots were constructed that show the different trends of the variables evaluated and how they affect production rate.

The results demonstrate the importance of proper well landing with strong influence of reservoir quality on postfracturing production results. The channel fracturing technique offers near-infinite fracture conductivity and shows very promising results compared with conventional treatments. Pumping the bigger fracturing jobs typically yields better production results, but proppant type and schedule should be designed accounting for reservoir quality. Pad volume should be designed to achieve optimum pressure at the end of the treatment, not too high but not too low. Post-fracturing production parameters are as important for the well performance as the stimulation treatment itself. The analyses identified the key post-fracturing production drivers in the gas reservoirs and ways to improve production of future wells drilled in various formations under similar conditions.
Validating Hydraulic Fracturing Properties in Reservoir Simulation Using Artificial Neural Networks
Authors: BuKhamseen Nader Y. , Ertekin Turgay
Published: June 2017

This paper presents a workflow to validate the hydraulic fracture properties in the reservoir simulator after the fracture job has been completed. The workflow incorporates artificial neural networks (ANN) as the engine behind the validation process. The required hydraulic fracture parameters that need to be fed to the reservoir simulator are mainly the fracture half-length, fracture permeability, and fracture width. These parameters constitute the fracture conductivity and are used to match the production and pressure profiles after the fracture job is completed.

If the reservoir simulation model has a satisfactory history match, the model response after the fracture job should not drastically deviate from the observed well response. If that deviation occurs, the developed ANN is introduced to help in figuring out a set of fracture conductivity parameters that match the observed data. The process starts by running the reservoir simulator to generate several data sets with variable fracture conductivity parameters to be used for training and testing the ANN. The ANN then outputs the fracture conductivity parameters based on the observed pressure and production profiles. The suggested output of the ANN is eventually validated with the reservoir simulator to check for the results accuracy.

This workflow has been theoretically tested on a synthetic reservoir model with heterogeneous reservoir properties. A fracking job of up to five stages is performed on wells in a low permeability oil reservoir. Results show the ANN is able to reproduce the fracture conductivity parameters with up to 84% accuracy when the stimulated well has been in production for one year. This number rises to 96% when additional year of production data is collected.

The availability of different training algorithms makes the artificial neural networks a fast and reliable tool to analyze the relationships between various parameters. As the results of this paper suggest, the reservoir simulation model can be updated with the aid of ANN and without compromising the captured physics during the history match.
Two Component Lost Circulation Material for Controlling Seepage to Moderate Losses
Authors: Ramasamy Jothibasu , Amanullah Md
Published: June 2017

A two-component lost circulation material (LCM) system is developed to mitigate seepage to moderate type loss of circulation using materials and polymers having different physical and chemical properties. The first component or component I is a slurry containing a carrier fluid such as water, a particulate or filler material such as fly ash, a fibrous material such as polypropylene fibers, and a water absorbing acrylic polymer. The second component or component II is a solution of sodium hydroxide in water. Component II is used as activator and when in contact with component I, the sodium hydroxide triggers the polyacrylic polymers in component I to absorb water in the slurry. As a result the whole system is swollen up and a generation of thick mass of the system achieved. This approach is used to address the lost circulation scenarios while drilling through fractured and cavernous zones. A comprehensive lab testing of the two component lost circulation material system has been carried out using pore plugging test (PPT) apparatus to prove its efficiency to seal off the fractures of width up to 2 mm. The results of PPT experiments show that the two component lost circulation material system is capable of controlling loss of circulation into fractures of width up to 2 mm under high pressure (1500 psi) and high temperature (250 °F) conditions. The new two component lost circulation system will provide a reliable solution to address seepage to moderate type loss of circulation.
Pressure Transient Analysis of Vertically Fractured Well in Tight Oil Reservoirs with Rectangle Stimulated Reservoir Volume
Authors: Zhu Langtao , Liao Xinwei , Chen Zhiming
Published: June 2017

The technique of stimulated reservoir volume (SRV) is becoming a key measure to enhance vertical well productivity and ultimate recovery in tight oil reservoirs. After the SRV treatment, micro-seismic monitoring strongly shows approximate rectangle stimulated reservoir volumes with a single bi-wing fracture are generated. However, most published works on the pressure transient of vertically fractured wells assumed that the SRV is an approximate circle, and few works have been done to rectangle SRV.

In this paper, a new analytical pressure transient solution for vertically fractured wells (VFW), with rectangle SRV and a single bi-wing fracture, is derived under constant rate. First, a two-region composite model is established to model the VFW. The inner region is considered as rectangle dual-porosity with a single bi-wing fracture. In addition, this model also considers other multiple factors including stress-sensitivity effect of permeability, unsteady cross flow between matrix and fractures. Then, the trilinear flow model proposed by Brown is extended to handle the rectangle boundary and bi-wing fracture; the Pedrosa's perturbation and Laplace transformation are applied to solve the non-linear equation, and the Kazemi's method is adopted to simulate the unsteady cross flow, and the pressure equation for VFW is solved. After that, this analytical solution is applied to the real cases from Ordos Basin reservoir to conduct equation validation. Finally, sensitivity studies are conducted to evaluate the effect of some critical parameters on pressure behavior of VFW.

The results of verification show there are great agreements. Results from this study show that the special flow regimes for a VFW in tight oil reservoirs includes (1) linear flow for the effect of bi-wing fracture conductivity, (2) SRV width effect flow, (3) inner boundary-dominated flow. The linear flow is stronger with the increase of bi-wing fracture length, bi-wing fracture conductivity, and SRV width. As the permeability of SRV increases, the inner boundary-dominated flow becomes more obvious. In addition, the SRV linear flow is stronger with the increase of SRV volume.

This work provides significant references for reservoir engineers in pressure transient analysis as well as fracturing evaluations of vertically fractured wells in the tight oil reservoirs.
Effect of Gravity on Near-Miscible CO2 Flooding
Authors: Al-Riyami Hamed F. , Kamali Fatemeh , Hussain Furqan
Published: June 2017

Carbon Dioxide (CO2) injection is considered one of the most widely used enhanced oil recovery (EOR) methods due to CO2 availability, applicability. Contributing to its popularity is the ability to perform carbon capturing and storage alongside EOR in which CO2 is stored in reservoirs to mitigate global warming potential. Experiments have been performed to measure oil recovery factor, CO2 storage efficiency, and co-optimization function of a CO2 flood in horizontal cores but none has studied the effect of gravity on all three.

This paper presents horizontal and vertical CO2 flooding experiments to quantify the gravity effect on oil recovery and CO2 storage. Irreducible water saturation of 27% represents the initial condition for both experiments. A homogeneous Bentheimer sandstone core is used while a mixture of hexane (65%) and decane (35%) represents the oil phase. The Oil recovery, pressure drop and effluent compositions are recorded during the experiment.

It was found that vertical flood exhibited high displacement efficiency but low volumetric sweep efficiency and by eliminating the effect of gravity, not only oil recovery increases, but also CO2 storage efficiency. In the vertical flood, oil recovery, CO2 storage efficiency, and the co-optimization function increase by 24%, 7%, and 15%, respectively, compared to horizontal flood. The stabilized displacement front delays breakthrough and effectively improves oil recovery and storage efficiency.
Nano-Scale Imaging at Crude Oil/Brine/Rock Interface in Carbonates: A Pore Scale Approach
Authors: Gmira A. , Al-Enezi S. M. , Cha D. K. , Yousef A. A.
Published: June 2017

Smart water and low-salinity waterflooding showed encouraging results for oil recovery in carbonate and sandstone reservoirs. Therefore, understanding of multiphase flow phenomena in reservoir rocks is critical to optimize injected water formulations and increase oil recovery. Various micro- and macroscopic techniques including NMR, surface charges, IFT, contact angle and coreflooding have been extensively used to understand the underlying mechanisms responsible for rock wettability alteration. However, it is challenging to understand the behavior of reservoir fluids and carbonate rocks at nano-scale with conventional methods, hence there is a need for advanced technologies to identify fluid phases and distributions at pore scale. The primary objective of this study is to develop an experimental protocol using Cryogenic high resolution focused ion beam (Cryo-FIB SEM) equipped with energy dispersive spectroscopy (EDS) and apply the developed protocol to study the impact of ions on carbonate rock/crude oil/brine interface at nano-scale. Cryo FIB-SEM preparation and imaging provide pore structure, connectivity and fluids distribution at carbonate pore scale. While, EDX analysis gives an insight of the compositional distribution and elements mapping. For carbonates exposed to calcium chlorides, SEM analysis showed the presence of hydrocarbons with a newly formed phase inside the pores, indicating the presence of high concentration of oxygen bonds. While no newly formed phase was observed for carbonate rock exposed to a complex brine. EDS analysis have also provided an elemental mapping based on the composition of the brine used. This feasibility study showed that the experimental protocol permits the observation of carbonate porosity morphology, fluids distributions inside the pore and elemental mapping across the surface for a better understanding of the crude oil/brine/carbonate system.
Use of Local Binary Pattern in Texture Classification of Carbonate Rock Micro-CT Images
Authors: Rahimov Khurshed , AlSumaiti Ali M. , AlMarzouqi Hasan , Jouini Mohamed Soufiane
Published: June 2017

A newly emerged technique known as Digital Rock Physics demonstrates an ability to characterize properties of the porous media. This technique is based on the imaging of rock micro-structure using a micro-CT scanner. Images are segmented based on their grayscale values to extract pore network from the solid phase. Then, rock properties are estimated using extracted pore network and numerical simulations. Porosity and absolute permeability are two essential properties that can be derived from grayscale images. These properties represent storage and flow capacity of the rock.

Some rock samples, particularly carbonate rocks have complex micro-structures at several length scales. Due to limited image resolution, 3D images of carbonate rock may not have top-bottom pore connectivity. In this case, one unable to simulate fluid flow throughout the images. Therefore, permeability is computed on small image sub-volumes, where pore connectivity is revealed locally. Such approach requires long simulation runs.

In this paper, a new approach is proposed to estimate permeability from 3D carbonate rock images, where pore connectivity is not revealed from top to bottom. In this approach, first a number of texture classes that represents various textures in the 3D image are identified. For each identified texture class, several sub-volumes from the 3D image are extracted. These sub-volumes are representative of the identified textures and have local pore connectivity. To simulate fluid flow through the pore network of extracted sub-volumes Lattice Boltzmann method (LBM) is used. Permeability is then calculated using Darcy's equation. After determining permeability ranges of each textural class, the 3D image is divided into sub-volumes. Then, each sub-volume is classified into one of the specified texture classes using a modified version of the texture classification algorithm, Local Binary Pattern (LBP). In this study, traditional 2D LBP texture feature vector is adopted to handle 3D volume classification. After classification, each sub-volume is assigned a permeability value that is equivalent to its texture class. Finally, the permeability of the whole 3D image is computed by simulating Darcy's flow through the all sub-volumes.

Preliminary outcomes of the proposed technique indicate that it is able to closely estimate experimental results from the laboratory.
Remaining Oil Saturation Measurements for CO2-EOR Pilot in Saudi Arabia
Authors: AlOtaibi Fawaz , AlOsaimi Falah , Sanni Modiu , Kokal Sunil , Ali Razally , Alhashboul Almohanand
Published: June 2017

Enhanced oil recovery by CO2 injection is an effective method for recovering additional oil beyond water flooding. In recent years CO2-EOR has garnered considerable attention from an environmental perspective as it is considered a green-house gas. Saudi Aramco is implementing its first CO2-EOR and sequestration pilot project in a slightly depleted part of a carbonate reservoir. An important aspect of the pilot testing is the measurements of remaining oil saturation (ROS) before and after the CO2 flooding. This paper discusses a number of methods and techniques for ROS quantification before CO2 injection in the ongoing CO2-EOR pilot project. The suite of tests provide pre-CO2 injection saturations. Similar tests are planned post-CO2 injection to determine the reduction in ROS after the pilot has been completed.

Several methods have previously been used to determine ROS in oil reservoirs. In this study different logging technologies were utilized for quantification of ROS before CO2 injection to generate baseline data. The logging included resistivity and dielectric techniques. These techniques were also combined with physical formation fluid tester and sponge core analysis to determine ROS in the targeted carbonate reservoir. Finally the results are compared with a single well chemical tracer test which was conducted in the area.

This paper presents the results from various methods and explores the effect of different parameters such as lithology, porosity, salinity and water saturation on ROS quantification. The results from near wellbore techniques are compared with data from sponge core as well as the single well chemical tracer test. Methodologies of raw data processing and their interrelations are shared. This paper provides new insights into how various logging tools and coring can be optimized in the future to increase the certainty of ROS measurements.
Hemp Yields and Its Rotation Effects on Wheat under Rainfed Mediterranean Conditions
Authors: Gorchs Gil , Lloveras Jaume , Serrano Lydia , Cela Sebastián
Published: June 2017

Core Ideas

Rainfed Mediterranean environments might be suitable for double‐purpose hemp production.

Hemp is a good predecessor for wheat under rainfed Mediterranean conditions.

The beneficial effects of hemp on the subsequent wheat yield appear to last for 2 yr.

Monocropping hemp over 2 yr, does not reduce its grain and biomass yields.

Hemp (Cannabis sativa L.) has a low impact on the environment requiring few added resources, and has multiple downstream applications. There is little information on hemp biomass, seed yields, and response to NPK fertilization under humid rainfed Mediterranean conditions. Moreover, the effects of hemp on subsequent wheat (Triticum aestivum L.) crops have not been determined. To address these issues, we performed a field study for 6 yr in Catalonia (northeastern Spain). Hemp treatments included: hemp monoculture, unfertilized hemp succeeding wheat, and NPK‐fertilized hemp succeeding wheat. In turn, wheat treatments included: wheat monoculture, first‐, second‐, and third‐year wheat succeeding unfertilized hemp, and first‐, second‐, and third‐year wheat succeeding NPK‐fertilized hemp. The hemp biomass yields (5340–10,090 kg ha−1) were similar to or lower than those achieved in other European regions whereas the hemp seed yields were relatively high (604–1434 kg ha−1). Both the biomass yield and seed yield greatly increased with NPK fertilization. The rotation effects of hemp on the subsequent wheat crops increased the wheat yield by 1368 and 155 kg ha−1 in the first and second years, respectively, but in the third year the yield was similar to the wheat monoculture. The beneficial effects of hemp on wheat therefore appear to last for 2 yr. We conclude that dual‐purpose hemp (harvested for fiber and seed) is an excellent predecessor for wheat, improving the sustainability of cereal‐based cropping systems under humid rainfed Mediterranean conditions.
Can Edaphic Variables Improve DTPA‐Based Zinc Diagnosis in Corn?
Authors: Barbieri Pablo A. , Sainz Rozas Hernán R. , Wyngaard Nicolás , Eyherabide Mercedes , Reussi Calvo Nahuel I. , Salvagiotti Fernando , Correndo Adrián A. , Barbagelata Pedro A. , Espósito Goya Gabriel P. , Colazo Juan C. , Echeverría Hernán E.
Published: June 2017

Core Ideas

DTPA‐extractable Zn is often used to predict corn response to Zn application.

Can DTPA–Zn‐based diagnosis be improved by considering other soil properties?

Soil properties did not contribute to explain corn grain yield response.

DTPA–Zn allowed to discriminate sites based on their response to Zn fertilization.

We determined a Zn‐critical range from 0.86 to 1.30 mg kg−1 (n = 64).

Current zinc (Zn) diagnostic methods for corn (Zea mays L.) are often based on soil DTPA (diethylenetriamine‐pentaacetic acid) extractable Zn (DTPA‐Zn). However, calibration of the DTPA‐Zn test may be influenced by other soil properties such as pH, organic matter (SOM) and available Bray‐P (PBray‐1). Our objective was to assess the contribution of soil properties to a DTPA‐Zn model used to predict corn response to Zn fertilization. We conducted 64 field trials with two Zn‐fertilization treatments: with and without Zn fertilization. In all sites, we measured SOM, PBray‐1, pH, and DTPA‐Zn at 0‐ to 20‐cm depth before sowing. Yield difference between Zn‐fertilized and unfertilized treatments (Ydifference) was significant in 33% of the experimental site‐years. In responsive site‐years, the average Ydifference was 0.98 Mg ha‐1 (11.4%). Soil organic matter was the only property that was a significant addition to the DTPA‐Zn model for predicting the corn relative yield (Model R2 including SOM = 0.27). However, the improvement was nominal (Partial R2 of SOM = 0.06). Use of DTPA‐Zn alone was suitable to discriminate Zn responsiveness among site‐years based on the Ydifference by correctly diagnosing 81% of the outcomes. We determined three soil DPTA‐Zn ranges with different probability of resulting in a Ydifference greater than zero when fertilized with Zn: high (<0.9 mg kg‐1), medium (0.9–1.3 mg kg‐1), and low (>1.3 mg kg‐1). These soil‐test‐based Zn recommendations improve the identification of Zn‐deficient soils allowing prevention of yield loss from Zn deficiency and more rational use of Zn fertilizers.
Measured Soil Moisture is a Better Predictor of Large Growing‐Season Wildfires than the Keetch–Byram Drought Index
Authors: Krueger Erik S. , Ochsner Tyson E. , Quiring Steven M. , Engle David M. , Carlson J.D. , Twidwell Dirac , Fuhlendorf Samuel D.
Published: June 2017

Core Ideas

Fraction of available water capacity (FAW) was determined from measured soil moisture.

Wildfire relationships were compared for FAW and Keetch–Byram drought index (KBDI).

Growing‐season wildfire danger was more accurately represented by FAW than KBDI.

Neither FAW nor KBDI alone accurately represented dormant‐season wildfire danger.

We recommend replacing KBDI with FAW in growing‐season wildfire danger assessments

In situ soil moisture measurements have the potential to improve wildfire danger assessments, which often rely on the Keetch–Byram Drought Index (KBDI) as a soil moisture surrogate. However, the relative merits of measured soil moisture and KBDI as indicators of wildfire danger are unknown. Therefore, our objectives were to (i) identify relationships between drought indices (KBDI or fraction of available water capacity, FAW) and wildfire size for 34,939 growing and dormant‐season wildfires, (ii) compare relationships between each drought index and wildfire probability for 501 large (≥ 405 ha) growing‐season and dormant‐season wildfires, and (iii) quantify relationships between KBDI and FAW for each season in Oklahoma, the United States. Neither KBDI nor FAW accurately represented dormant‐season wildfire danger, with wildfires ≥ 121 ha occurring across nearly the entire range of each index. During the growing season, however, we found that a smaller percentage of wildfires ≥ 121 ha occurred under extreme levels of KBDI than under equivalent levels of FAW (66% vs. 81%), and a logistic regression model based on FAW correctly classified more growing‐season days with large wildfires than the KBDI model (84% vs. 79%). Furthermore, while FAW represented soil moisture in near real‐time, KBDI responded slower to soil drying and recharge, so FAW provided about 10 d earlier warning of extreme wildfire potential for the 10 largest growing‐season wildfires in our study. We therefore recommend replacing KBDI with FAW in growing‐season wildfire danger assessments in Oklahoma and regions with similar climate (temperate, subhumid to semiarid) and vegetation types (primarily herbaceous).