bluuebunny/crossref_metadata_2025_split huggingface dataset:
Materials for Controlling Severe Lost Circulation - Laboratory Evaluation
Authors: Miranda C. R. , Oliveira J. L. , Cavalcante G. M. , d'Almeida A. R. , Pereira R. F. , Santos R. L. , Surmas R. 
Published: May 2017

Abstract
Lost circulation is still today one of the most costly problems for oil and gas operators. It may occur into permeable formations, depleted zones, induced or nature fractures and cavernous formations while drilling, cementing or during workover jobs in the well.
This paper focus on the evaluation of bridging and reactive systems in remediating severe losses based on their performance in a dedicated experimental facility.
Laboratory apparatus commonly used to evaluate lost circulation materials generally consist in modified API-fluid loss devices using slotted metal discs, ceramic discs or natural cores. These devices are suitable to simulate permeable formations or depleted zones, but they do not simulate severe lost circulation scenarios that occur in induced or nature fractures and in cavernous formations. For that reason, a specific laboratory apparatus was built, where the performance of several materials was evaluated and classified according to different severity levels.
This paper summarizes the efficiency of available commercial bridging (granular, fibers and flakes) and reactive systems in remediating severe losses according to different severity levels imposed in the developed severe lost circulation apparatus.
Besides commercial products alredy used to control losses, hydrated bentonite pellets have been evaluated as bridging material.
Combining Physics, Statistics and Heuristics in the Decline Curve Analysis of Large Datasets in Unconventional Reservoirs
Authors: Holanda Rafael Wanderley , Gildin Eduardo , Valkó Peter P. 
Published: May 2017

Abstract
Analytical single well models have been particularly useful in forecasting production rates and Estimated Ultimate Recovery (EUR) to the massive number of wells in unconventional reservoirs. In this work, a physics-based decline curve model accounting for linear flow and material balance in horizontal multi-stage hydraulically fractured wells is introduced. The main characteristics of pressure diffusion in the porous media and the fact that the reservoir is a limited resource are embedded in the functional form, such that there is a transition from transient to boundary dominated flow and the EUR is always finite. Analogously to the frequently used Arps hyperbolic, the new model has only three parameters, where two of them define the decline profile and the third one is a multiplier.
This model is applied to a large dataset in a workflow that incorporates heuristic knowledge into the history matching and uncertainty quantification by assigning weights to rate measurements. The heuristic rules aim to lessen the effects of non-reservoir related variations in the production data (e.g. temporary shut-in due to fracturing in a neighboring well) and emphasize the reservoir dynamics to perform reliable predictions. However, there are additional degrees of freedom in the way these rules define the values of the weights, therefore a criteria is established that "calibrates" the uncertainty in the probabilistic models by adjusting the parameters in the heuristic rules. Uncertainty quantification and calibration is performed via a Bayesian approach with hindcasts. This methodology is implemented in an automated framework and applied to 992 gas wells from the Barnett shale. A comparison with the Arps hyperbolic, Duong and stretched exponential models for this dataset shows that the new model is the most conservative in terms of estimated reserves.
Integrated Modeling of Formation Damage and Multiple Induced Hydraulic Fractures During Produced Water Reinjection
Authors: Fischer K. , Ferreira F. C. , Holzberg B. B. , Pastor J. S. , Reinli L. , Furuie R. , Vasconcelos D. M. , Dutra T. A. 
Published: May 2017

Abstract
During produced water reinjection into an oilfield, the formation near the wellbore is progressively damaged due to total suspended solids (TSS) and oil particles in the injected water (OIW). This typically increases the bottom-hole injection pressure over time. Furthermore, if the water is injected in the oil zone, the initial bottom-hole injection pressure may already be high from the start due to water mobility constraint and oil viscosity. This study aims to model the generation of hydraulic fractures induced under different conditions, their geometrical characteristics and corresponding development over time. Such information is key to reservoir simulation for the secondary oil recovery and to reservoir integrity assessment.
Four disciplines are integrated into the proposed workflow: reservoir flow simulation, formation damage modeling, reservoir geomechanics, and the simulation of hydraulic fracturing. First, a sector model around an injector well is extracted from the full-field reservoir simulation of the case-study reservoir. In the reservoir flow simulation, a formation damage model is implemented, calibrated from injection rate, bottom-hole pressure, TSS and OIW actual data. At specified time steps, the flow simulator passes pore pressure profiles of the sector model to the geomechanical simulator, which computes the corresponding changes in stress and deformation.
The updated in-situ stress field, in combination with the petrophysical model applied for the flow simulation, is provided to the hydraulic fracturing simulator, which tests for the development of the hydraulic fracture and computes its geometry. The resulting hydraulic fracture is mapped back into the reservoir flow model to account for the local increase of permeability of the cells hosting the fracture. The workflow then enters into a loop starting again with the flow simulation, and the further development of the fracture under changing conditions is tested and modeled.
The proposed workflow was successfully applied to an injection well in an offshore field. Four scenarios considered different initial formation saturation, injected fluid viscosity and the conversion of a producing well into an injector. Multiple fractures with different characteristics, fully contained inside the reservoir, were predicted for each scenario and gave insights into the hydraulic fracture development during produced water reinjection.
The proposed method and workflow have the potential to significantly improve the reservoir simulation of the water injection process for secondary recovery or pressure maintenance by providing insights into how induced fracture geometries will influence the injection pressure and reservoir sweep efficiency. It also may provide valuable information to assess the integrity of reservoir cap rock during produced water reinjection.
Models for Calculating Organic and Inorganic Porosities in Shale Oil Reservoirs
Authors: Piedrahita J. A. , Aguilera R. 
Published: May 2017

Abstract
The objective of this study is to present methods for calculating organic and inorganic porosities in shale oil reservoirs. This is achieved by combining density, neutron and NMR logs as well as laboratory geochemical and synthetic geochemical properties of organic matter. The study also presents methods for calculating these porosities when all the above data are not available. This is important as data scarcity is a common problem in most shale reservoirs.
Shales are generally composed by clays, inorganic matrix, organic matter and natural fractures. In this study, responses of density, neutron, and NMR logs are written in terms of properties of each shale component including clays, solid and porous volume for both inorganic (including natural fractures) and organic matter. Different analytical models are built depending on available input data and the approach used to convert weight total organic carbon (TOC) to TOC volume percentage. However, as is usually the case, the availability of different sources of information including geochemical data, routine and/or special core analysis will enhance the validity of the interpretation.
Models developed in this study indicate that organic porosity results (intrinsic and scaled to total volume) are very consistent with values measured in the laboratory and values reported in the literature. There are three approaches for converting weight TOC to percent volume TOC. Our results show that these three approaches have to be used carefully. Their indiscriminate use can lead to errors as the organic porosity is very sensitive to the TOC transformation. The organic porosity is also very sensitive to properties assumed for each component of the reservoir rock.
Depending on petrophysical and reservoir engineering needs, the organic porosity can be easily scaled to the volume of only the organic matter (intrinsic organic porosity) or to the bulk volume (total organic porosity) of the total system. In addition to organic porosity, the models developed in this study also allow calculating kerogen volume and its respective solid portion, allowing thus an estimate of solid kerogen and porosity within the kerogen material. Furthermore, the models also allow calculating inorganic porosity (matrix plus natural fractures).
Unlike current models that use separately conventional logs or NMR logs to calculate the porosity associated with organic matter, this study integrates all these logs as well as laboratory and synthetic geochemical properties of organic matter to develop new methods for estimating rigorously-scaled organic porosity.
Use of Dynamic Data for Estimating Average Reservoir Pressure, OGIP, and Optimum Well Spacing in Shale Gas Reservoirs
Authors: Orozco D. , Aguilera R. 
Published: May 2017

Abstract
The average reservoir pressure is a key parameter in material balance calculations, but its determination is challenging when dealing with shales because of their low and ultra-low permeabilities. This paper presents an easy-to-reproduce methodology for calculating the average reservoir pressure from flowing data, and its use in a new Material Balance Equation (MBE) that considers the simultaneous contribution of free, adsorbed and dissolved gas.
The procedure developed in this paper uses a modified gas compressibility factor (Z') introduced in the new MBE. Since Z' accounts for the combined effect of free, adsorbed and dissolved gas, then total original gas-in-place (OGIP) can be determined from extrapolation of the MBE straight line to an average reservoir pressure equal to zero. Drainage area can be estimated on the basis of the calculated OGIP and volumetric equations. As such, the methodology offers the potential to help improve well spacing in shale gas reservoirs in such a way that no stranded gas is left in the reservoir, or that not excess wells are drilled in the field. This can help to improve recoveries from shales by assisting in the determination of the optimum number of wells needed to drain efficiently a given play.
In conventional reservoirs, a well is shut-in and the average reservoir pressure is determined from the corresponding pressure build-up test. But, for the case of unconventional shale gas reservoirs, shutting the wells in is unacceptable due to the long time it would require for estimating average reservoir pressure. The methodology developed in this paper for shale gas reservoirs circumvents this problem by using dynamic data.
Production data from multi-stage hydraulically fractured horizontal wells completed in a Canadian shale gas reservoir are used for testing the effectiveness of the new methodology. Comparison of typical well spacing values vs. the drainage area calculated with the new methodology leads to the conclusion that, probably, only 40% of the gas is being drained efficiently.
The novelty of this work relies on the development of a methodology for calculating average reservoir pressure, OGIP, drainage area, and optimum well spacing in shale reservoirs through the combination of dynamic data and a new MBE that considers simultaneously the effects of free, adsorbed and dissolved gas.
An Overview of Deepwater Well Integrity Developments After the Blowout of Macondo
Authors: Santos O. L. , Ribeiro P. R. 
Published: May 2017

Abstract
Well integrity undeniably is considered one of the most important topics of the petroleum industry. Failure in not keeping a well integrity system functioning adequately may result in disastrous accidents called blowouts with all tragic consequences that they may bring: loss of human lives, loss of drilling equipment or production facilities, loss of hydrocarbon reserves and pollution. Also, well integrity issues may lead to substantial financial losses during the entire well life cycle as a result of non-productive operational time and/or remedial solutions. The situation is aggravated when considering deepwater scenarios.
Unfortunately, in 2010 the oil industry faced its worth accident caused by the loss of well integrity: the blowout of Macondo in the Gulf of Mexico with devastating consequences to the oil industry. The accident has been demanding from all players (operators, drilling contractors, service companies, regulators, industry organizations, academia and training providers) a huge amount of effort to minimize the risk of having this kind of accident repeated. Originally, those efforts were aimed at deepwater drilling activities in the Gulf of Mexico but with time they were disseminated throughout the oil industry activities all over the world.
Significant progress has been done to enhance the safety during all phases of the well life cycle since the Macondo blowout. This paper intends to present and discuss with actual examples the latest technical and managerial developments with emphasis in deepwater situations since the tragic blowout of Macondo happened. Particular attention is given to the following aspects: operational guidelines, regulations, well control equipment, training and competency assurance, well integrity management systems, novel technologies and research.
New Drill Pipe Size Improved Drilling Efficiency in Shale Plays
Authors: Lafuente M. , Granger S. 
Published: May 2017

Abstract
Drilling horizontal wells typically requires a tremendous engineering effort due to operational challenges with wellbore hydraulics, borehole cleaning, drill string buckling, poor weight-on-bit transfer, and reduced drill pipe service life. Typical symptoms include reduced rate of penetration, difficulty sliding, frequent wiper trips, excessive back-reaming, high torque/drag, and severe drill pipe wear coupled with potential connection damage.
In response to these industry needs, a new type of drill pipe optimized for shale drilling was developed. Modelling with several software packages was performed to compare this new 4-1/4" diameter Shale Drill Pipe (SDP) against conventional 4" diameter drill pipe in a typical 20,000 ft MD Bakken well. Three main areas of improvement were identified: hydraulics, buckling resistance, and reduced tube wear.
For one operator in Western Oklahoma, SDP provided a solution to some operational restrictions. The Operator elected to use the SDP primarily due to standpipe pressure limitations of the drilling rig (+/- 3,400 psi). The expectation was that SDP would improve performance in these wells, while still offering an economic alternative to other, more costly solutions such as using a more costly rig.
This paper will examine the field results of eight horizontal wells drilled in Western Oklahoma. The first three, which served as the baseline, were drilled to the planned total depth using a drill string with conventional 4" diameter drill pipe while the other five wells were drilled using the newly developed 4-1/4" diameter Shale Drill Pipe. Improvements in the drilling process observed with this new technology, particularly a reduction in stand pipe pressure, will be demonstrated. This innovative new design in drill string technology is one of the industry's first drill pipe based solutions addressing drilling challenges at a more fundamental level.
Non-Destructive Measurement of Porosity, Compressibility and Gas Sorption in Core Plugs from the Wolfcamp Shale
Authors: Tovar F. D. , Barrufet M. A. , Schechter D. S. 
Published: May 2017

Abstract
This work presents the carbon dioxide (CO2) storage capacity of the Wolfcamp formation in West Texas. The potential of CO2 for enhanced oil recovery from unconventional liquid reservoirs have been under investigation in recent years. Quantifying the rock ability to store CO2 is necessary for the economic assessment of CO2 EOR, and for the evaluation of carbon sequestration capacity. We measured the porosity, the rock compressibility and the CO2 sorption in sidewall core plugs taken from two wells drilled in the Wolfcamp shale. Computed tomography scanning technology was used to image the samples and investigate the relation between rock density and porosity, and rock density and CO2 sorption.
A gas expansion pycnometer was used for the experiments. To accommodate the challenges associated with extremely tight rocks the equipment was provided with accurate temperature control, and a high resolution gauge with the capability of recording pressure as a function of time. Porosity and compressibility were measured simultaneously using helium. We used different treatments for the rock compressibility and explored its behavior at low pressure. A Langmuir isotherm was used to account for sorption of CO2 on the organic matter of the shale. The volume available for free gas was corrected by incorporating the rock compressibility and the volume of the layer of sorbed CO2 in the analysis of the sorption data.
This study adds to the understanding of the storage capacity of the Wolfcamp shale. We found the porosity to be between 5.94 and 10.30%, the Langmuir volume between 38.77 and 154.51 scf/ton, and the Langmuir pressure from 512.59 to 1384.52 psig. Using CT number as a proxy for total organic content, we observed a linear relation between CT number and sorption capacity. Porosity also showed a linear relation with CT number. Free CO2 storage is the main storage mechanism, at pressures above 2500 psig (for all samples) accounting for more than 80 %. Sorption is a relevant storage mechanism at low reservoir pressure. Neglecting the rock compressibility or the volume of the sorbed layer can lead to wrong estimates of sorption capacity.
The techniques developed in this work provide for an economic and accurate mean of measuring porosity, compressibility, and sorption in tight unconventional core plugs. The use of a non-destructive approach is necessary to characterize core plugs that must remain intact for further testing such as the evaluation of enhanced recovery techniques in unconventional reservoirs. This research provides relevant data for the economic assessment of CO2 EOR in the Wolfcamp and the potential for carbon sequestration. The linear relations we observed for both, porosity and sorption capacity, with CT numbers, are of extreme interest as they can be exploited for faster petrophysical evaluation of unconventional tight rocks.
New Insight to Apply Azimuthal Geosteering
Authors: Cedeno D. , Alvarez A. , Fuentes J. , Portilla C. , Machare V. , Erazo R. , Escobar K. , Cedeño R. E. 
Published: May 2017

Abstract
This work highlights the use of tools that can perform multi-space directional multifrequency propagation measurements to drill horizontal wells in real time. The same that provide information such as the distance of the geological limits and the orientation of fluids through interpretations that can be executed in real time and recorded mode. The new concept of measurements and principles involves tilted and transverse antennas to provide measurements that are sensitive to the orientation of the tool with respect to the geological structure around the well, enhancing real time decision making and improving the geo-position trajectory of productive wells.
Methodology for Petrophysical and Geomechanical Analysis of Shale Plays. Case Study: La Luna and Capacho Formations, Maracaibo Basin.
Authors: Lobo C. , Molina A. , Faraco A. , Mendez J. , Delgadillo J. , Rincon G. 
Published: May 2017

Abstract
According to EIA (Kuuskraa et al., 2013) and PDVSA Exploration (Molina et al., 2014), the Maracaibo Basin in Western Venezuela has two stratigraphic units of Late Cretaceous age which are considered as important unconventional shale plays in Latin America: La Luna Formation and La Grita Member of Capacho Formation. Venezuela is ranked in 7t place in shale oil resources, with an estimate above 13,000 MM barrels, and ranked in 13th place in shale gas resources, with an estimate above 201 TCF. In order to evaluate the mentioned shale plays, a methodology was developed through the integration of petrophysical, geochemical and geomechanical analysis.
The complete evaluation methodology has 4 phases: 1) petrophysical evaluation, that includes multimineral evaluation, porosity estimation and calibration with mineralogical analysis; 2) TOC content evaluation, that includes TOC content estimation, using 3 methods: density logs (Schmoker, 1979), gamma ray logs (Schmoker, 1981), sonic and resistivity logs (Passey et al., 1990), and porosity associated with organic matter; 3) geomechanical evaluation, that includes rock mechanical properties estimation, state of stress determination and brittleness index estimation, using 3 methods: mineral content (Jarvie et al., 2007), elastic properties (Rickman et al., 2008) and a modified method of Grieser-Bray (2007), calibrated with geomechanical field test (XLOT, microfracs and minifracs); and 4) determination of most prospective intervals for completion.
La Luna Formation and La Grita Member of Capacho Formation are mainly composed by carbonatic rocks, with high content of calcite (above 75%) and low content of clay minerals. In both units, the estimation of TOC content varies from 0.50 to 9%. Mechanical properties show moderate values of Poisson's ratio (0.20 to 0.32), high values of Young's modulus (0.80 to 9.60x 106 psi) and UCS (6.20 to 31.00x 106 psi). In the Cretaceous sequence, the state of stress changes according to geographic location in the basin, from normal in northwest region and central lake region, to transcurrent and reverse in southeast region. The brittleness index estimated for different methods varies from 0.54 to 0.85, which indicate that both units may be classify as brittle.
The integration of geomechanical and petrophysical analysis allowed identifying prospective intervals in both units, with thickness between 20 to 100 ft. Therefore, the study indicates that both units show very good conditions for horizontal drilling and hydraulic fracturing. Moreover, the comparison of various estimation methods of TOC content and brittleness index allowed to observe the uncertainty presented by these parameters in analysis of shale plays.