bluuebunny/crossref_metadata_2025_split huggingface dataset:
Connecting Wells in Environmentally Sensitive Areas Using Magnetic Ranging-While-Drilling Technology for Enhanced Hydrocarbon Recovery
Authors: Lips Jean Paul , Rassadkin Georgy , Dorey Jamie 
Published: July 2020

Abstract
When emergency situations in environmentally sensitive areas occur, drilling a relief well to intercept and kill the blowout well often requires various types of magnetic ranging technologies to navigate into the problematic well. Outside this scenario, we do not commonly hear about magnetic ranging.
The main objective of this paper is to raise awareness among operators about magnetic ranging-while-drilling technology as wellbore placement service to make planned wellbore intersections to boost production.
Reactivation of mature fields is often an economically viable option when demand for energy pushes oil prices upwards. In order to boost production from an existing mature field, an operator provided a service company with an interesting challenge: utilize proven directional drilling expertise in conjunction with alternative wellbore positioning techniques to drill two high-angle deviated wells from opposing directions and intercept a common vertical producer well for a gravity drainage concept. During the pre-planning phase, one of the major challenges was MWD survey accuracy for the horizontal wells. The 2-sigma major-axis uncertainty of the MWD surveys after applied corrections at the point of planned contact with the vertical producer was over 106 ft while the size of the target to intercept was only 1 ft in the lateral dimension.
Implementation of magnetic ranging while drilling technology combined with north-seeking gyroscopic sensor allowed optimal positioning of all three wells relative to each other. Bottom hole assembly equipped with a smart mud motor, MWD, and magnetic bit-sub avoided collisions and steered successfully between other producing wells in the mature field. This challenging project from two opposite surface locations took several weeks of directional drilling and resulted in precise positioning both horizontal drainage sections within close proximity of vertical producer. Hydraulic communication with the vertical producer was successfully established from both horizontal wells after completion of the drilling operations.
Assessment of the Potential for Gas Production from Marine Methane Hydrate Reservoirs by Numerical Simulation
Authors: Tomasini Juan , Stephen Karl 
Published: July 2020

Abstract
In this work the potential for gas production from two selected methane hydrate deposits which are situated offshore from Uruguay is assessed along with the validity of numerical simulations as a tool for analysis in this environment. Gas hydrates are crystalline solids formed by gas and water, in which gas molecules are accommodated within a solid water lattice in a cage-like structure. They form in thermobaric conditions of relatively high pressure and low temperature which in nature occur in permafrost and deep water sediment environments. Marine methane hydrates represent a huge potential as an unconventional gas resource and production tests have already been perfomed offshore Japan and China confirming the validity of depressuration as a method of production.
Available 3D seismic data was utilized for the identification of interesting areas for gas hydrate studies focused on resource exploitation allowing the acquisition of the corresponding architectural parameters. Due to the lack of well data at the selected locations, geological models and reservoir properties were defined based on published data from studies on analogue situations including data from the first production test performed offshore of Japan. Reservoir simulations were carried out to assess the response of selected prospects to depressurization induced dissociation.
Two prospects, interpreted as turbidite type deposits and located at 1850 m and 788 m of water depth, were selected for the modelling studies. The simulation of short term production tests of 60 days indicates average gas release rate values from 34 100 std m3/d to 6700 std m3/d for the deeper and shallower prospect respectively. The simulations were greatly affected by geometrical non-geological parameters like the proximity of model boundaries as well as type and level of discretization. We found that for finer discretization cases, the use of logarithmically distributed radial grid cells led to the existence of artifacts at early time on the gas release rate curves while the use of uniformly distributed radial cells results in more stable behaviour of the gas release rate. Several realizations of the geological models were used and sensitivity analysis was carried out regarding permeability and hydrate saturation. A longer term production regime (10 years) for a heterogeneous layered case was also simulated for the deeper prospect resulting in very useful average gas release rates of approximately 70 000 std m3/d, essential to satisfy gas requirements of Uruguay. We predict that only a few wells would be needed.
For the first time, reservoir simulation was applied for prospects in Uruguay and the gas release potential for marine methane hydrate deposits in the Southern Atlantic margin was assessed. Simulation results are encouraging. Additionally the results of this work at the identified prospects may be useful for site selection for any future campaign for gas hydrate exploration offshore Uruguay.
New Alternative to Optimize Cyclic Steam Injection: Field Pilot
Authors: Bustos Acevedo Carlos Alberto , Yatte Garzon Fabian Camilo , Lozano Guarnizo Eduardo , Higuera Daniel 
Published: July 2020

Abstract
This paper presents a technical evaluation of the results obtained in a field pilot to optimize the cyclic steam stimulation (CSS) by evaluating the performance of the indicator of oil steam ratio (OSR). The pilot was based on numerical simulation, where several alternatives or strategies were identified to improve the current technique applied for wells with more of 15 cycles as a method of improved or enhanced recovery in a madure heavy oil field. In a heat transfer process, in this case used by cycle steam injection, once it has maximum use, the next step in most of the termal process is to apply or move to steam flooding tecnic, but the implementation of it requires high investments that currently are not viable. However, it is necessary to provide solutions that contribute to improve the CSS efficiency of the field.
The following workflow was developed: (1) research of literarature and field experiences of different alternatives to increase the actual CSS efficiency by only changing the steam injection strategy, without including additional costs related to additives or technologies. (2) selection of the pilot area based on the current petrophysical, production, steam injection conditions and supported by a numerical reservoir simulation model with different sensitivities to define the base case to be developed in the field and (3), the optimal case was implemented in the field during one year. Results are discussed in this paper. An area of the field under study was selected, considering the following conditions: low pressure, high water cut, number of CSS per well greater than 15, inefficient CSS response. (4) alternatives for the optimization of the CSS were identified; these were evaluated by numerical simulation and it was found the optimal development strategy the intermittent injection.
With these results, a field pilot was implemented which consisted of 3 injection wells in 3 different patterns, for a period of 12 months of evaluation. During this period, it was possible to reduce the strong decline in oil production presented in the area from 23% to increase to −25% A.e., saving 20,000 mmbtu/ of steam in a year, generating an increase in the OSR of 0.12 BBl / MMBTU; and a decreasing the number of well services jobs from 51 to 27. This result was achieved because areas with oil saturation that had not been previously stimulated in the conventional process of CSS were contacted under this new scheme. The current conditions of the field, low pressure and high saturation of unconnected remaining oil during the conventional cyclic steam injection until now applied in the field, led to propose new cyclic stimulation alternatives such as the one presented in this paper; highlighting the technical results of the pilot developed without additional cost, just changing the injection strategy to optimize the current state of the field.
A Gas Lift Innovative Completion Design for Extended Perforated-Interval Gas Wells. A 5 Year and 25 Wells Successful Experience in a Mature Gas Field, Agua Del Cajón Field, Neuquén Basin, Argentina
Authors: Bodini Santiago Alejandro , Gonzalez Montero Gustavo Daniel , Telleria Nicolas 
Published: July 2020

Abstract
Agua del Cajón Field produces from conventional and unconventional formations since 1970. As a mature gas field, the average gas rate per well is 7.000 m3/d with a GLR of 10.000. Reservoir pressure is 25% of its original and 70% of the wells produce from several formations, with perforated intervals longer than 500 meters.
As flow rate decreases, gas doesn't have enough turbulence to remove liquid, leading to an increase in dynamic bottomhole pressure due to liquid loading. This effect deepens the decline resulting in gas resources unproduced.
There are different solutions for these kind of problems: reducing wellhead pressure using compression, capillary strings for foamer injection, velocity string or gas lift.
Gas lift is an attractive solution to reach gas speeds higher than critical by injecting a supplementary gas flow. This technique has achieved good results during several years in Agua del Cajon field. Despite working properly in the tubing (being efficient to remove liquid from injection mandrels to surface), it didn't solve liquid accumulation in the perforated interval.
Capex developed a customized bottom-hole equipment that optimizes well performance, by injecting gas lift below the packer.
A cross-over packer with a concentric pipe design is used, allowing injected gas to be conducted through the annular space between them and to extract liquid and gas from the bottom of the well by the central tube of reduced diameter. The production gas can be produced with the liquid at the end of the pipe, or rise through the annular space (casing-outer tubing) and join the liquid production and injected gas through a crossover located below the packer. The advantage of this system is that it ensures the removal of liquids from the lower part of the well with an optimized flow of injection gas.
In the last 5 years, 25 devices were installed with operative success in all cases. Gas flow rate increased an average of 80% after the intervention. Liquid production increment is also observed in most cases. Reserves were gained as it was able to reduce the abandonment gas flow rate.
Combining Data Analysis and Simulation to Design the Largest Polymer Injection Pilot in Argentina
Authors: Perez Diego Gaston , Cocco Mauro Daniel , Pedersen Guillermo Alejandro , Volzone Dario , Fuzul Eduardo , Ursule Jean Philippe , Massaferro Jose Luis 
Published: July 2020

Abstract
Field tests, advanced logging and data acquisition are combined here with a multi scale reservoir model to select the sweet spot for a polymer injection commercial pilot with 19 injector wells.
We present as case study an on-going polymer injection project in a brown oil field in Golfo San Jorge Basin western flank, Argentina. Productive interval comprises a 1000 m column low net-to-gross fluvial succession in Bajo Barreal Formation. Field production is ∼100 cp oil with 94% watercut and low recovery after a 25-year waterflood.
From advanced logging we interpret waterflood response and mineralogy. We also acquire rock and fluid samples for lab analysis and execute several single well injectivity tests. Here we show the impact of this information when designing the pilot. Particularly, we ran production logs in three wells in a selected pilot area. These tests results proved their worth reducing greatly the uncertainty on production allocation and supporting our thesis relating connectivity and productivity.
Using this data, we build several dynamic models in different scales (from 10 km to 100 m) to capture depositional trends and to model stratigraphic and sedimentary heterogeneity. We use dynamic models on scales from field to plug combined with economic evaluation to improve the selection and to support decision-making.
Identification of the most sensitive parameters such as reservoir connectivity, current oil saturation, production allocation and polymer retention, validate expenditure on data acquisition on the most sensitive variables for the economic indicators.
Carbon Intensity of Unconventional and Latin American Oil Plays
Authors: Meehan Nathan , Jenvey Nigel , Datta Aparajita , Uppati Sai Pranav 
Published: July 2020

Abstract
Carbon intensity (CI) of oil and gas production varies widely across global oil plays. Life cycle extraction in the Latin American Region (LAR) has some of the highest and lowest values of CI and holds many opportunities to reduce carbon emissions and improve national wealth. Flaring and venting of associated or non-associated natural gas dramatically increases CI.
This paper applies peer-reviewed processes across broad averages of oil and gas activity in major fields around the world and compares them with both Latin American and North American oil plays. Ways to lower the carbon intensity for high CI fields in the region are discussed. Unique opportunities exist to minimize carbon intensity in both areas.
We perform well-to-refinery calculations of CI for major unconventional oil plays in all major Latin American fields, the largest North American unconventional plays and other major producing countries. This approach accounts for emissions from exploration, drilling & completions, production, processing, and transportation. The analysis tool is an open-source engineering-based model called Oil Production Greenhouse Gas Emissions Estimator (OPGEE). OPGEE makes estimates of emissions accounting using up to 50 parameters for each modeled field. This model was developed at Stanford University. Data sources include government sources, technical papers, satellite observations, and commercial databases.
Applied globally, OPGEE estimates show the highest values in areas with extensive flaring of natural gas and very heavy crude oils. Heavy oils require large energy inputs (e.g. steam flooding) and/or the use of light hydrocarbon diluents for transportation offset. OPGEE can be used to evaluate the CI impacts of public policy actions.
While both NA unconventional and LAR crudes will remain vital to regional and global supplies, unconventional production, especially from light tight oil is the most significant new source of fossil fuels in the last decade. Under a wide variety of carbon constraints, oil usage will continue for many decades and increase in the near term. Operators, governments and regulators need to be able to avoid "locking in" development of suboptimal resources and providing incentives for shale operators to manage resources sustainably. Oil producers must prepare by refraining from developing marginal projects, eliminating flaring, optimizing hydraulic fracture treatments, using improved recovery methods (e.g. enhanced oil recovery using anthropogenic CO2), reducing energy use, and eliminating unnecessary gas waste.
A Methodology to Use of RCX Straddle Packer Microfrac for the Determination of Minimum Horizontal Stress in Vaca Muerta Formation
Authors: Ferlaza Carlos , Merchán Vladimir , Teran Claudia , Paris Martin , Rabe Claudio , Baratcabal Julio 
Published: July 2020

Abstract
This paper describes the test protocols and procedures of RCX Straddle Packer Microfrac for the estimation of formation Breakdown, fracture propagation and fracture closure pressure at different levels in Vaca Muerta formation. As a result, the horizontal stress field can be estimated, which in turns allows to infer if the fracture scheme and productivity agree well with initial prognosis.
Historically, this tool had been used for the estimation of formation pressure and fluid samples for unconsolidated formations. However, a micro-fracture job, pump capacity, packer hermeticity and a well design test protocol were the key to allow get formation breakdown, fracture propagation, fracture closure through pumping flow back and fracture reopening in various cycles. Such procedure was performed at two depths with success. Selection of the test intervals involved a preliminary geomechanical model for the determination of stress conditions, mechanical properties and wellbore stability analysis to choose proper mud density to reduce the probability of well damage (breakouts mainly), which can compromise test hermeticity. Then, after drilling, well logs including wellbore image and caliper analysis enable the determination of test intervals with minimum damage.
In the test well, Microfrac tests were performed successfully on two intervals out of four selected. Interpretation allowed the estimation of closure pressure related to minimum horizontal stress. Moreover, a rough estimation of maximum horizontal stress, based on breakdown pressure and closure pressure was performed as well. Such results agree well with the initial geomechanical model. Strike slip regime was confirmed in such a way that no alarms were set for future development through horizontal wells. But it is necessary to make a deepper investigation to ensure a favorable anisotrophy stress ratio. Some areas with unfavorable vertical to horizontal stress ratio, have been show low performance productivity. The main advantages of this type of tests are: (i) the availability to acquire information through several depths in a vertical well. (ii) Tests were performed in open hole conditions. (iii) Horizontal in situ stresses can be estimated. (iv) Time efficiency in comparison with classical DFIT tests. (v) Calibration of geomechanical model for future development.
Through the application of this tool, a new methodology was set, which allows for an early diagnose of the horizontal stress field leading to the determination of stress regime. Therefore, if the worst-case scenario appears related to inverse stress regime, development plans can be reorganized, reducing potential economic losses, considering that, as had been demonstrated in Argentina, horizontal wells placed on inverse regime led to EUR lower than breakeven.
NMR Data Processing Using Gamma Functions for the Evaluation of Heavy Oil Reservoir in the Peregrino Field
Authors: Klein Katherine , Barbosa José , Salazar Jesus Pastor , Borri Javier , Arro Roberto 
Published: July 2020

Abstract
The use of Nuclear Magnetic Resonance (NMR) logs for petrophysical interpretation and evaluation in the oil and gas industry has increased in recent decades, especially in Brazil, where the use of this technology was increased by more than 400% from 2011 to 2018 (from 49 to 208 runs). This increased usaged occurred mainly because the porosity estimation provided by this technology is independent of lithology. Additionally, the porosity can be associated with different pore sizes. It can also be divided to quantify the fraction of porosity for the clay bound water, bound fluid by capillary forces and movable fluid by applying cutoff times in the spectrum of T2 distribution.
Nevertheless, the presence of heavy oil in the Peregrino reservoir, with oil viscosities ranging varying from 150 to 350 cP, complicates NMR interpretation because the signal from the oil decays with a time constant that is comparable with that of capillary or clay-bound water, affecting the determination of permeability and the fluid distribution.
This paper presents the results of applying innovative Gamma Inversion to process the logging-while-drilling (LWD) NMR data acquired in a well from the Peregrino Field, offshore Brazil. The Gamma Inversion process uses probabilistic functions, instead of exponential ones, to generate a T2 spectrum that is more consistent from a mathematical and geological point of view.
Applied Learnings in Reservoir Simulation of Unconventional Plays
Authors: Altman Raphael , Tineo Roberto , Viswanathan Anup , Gurmen Nihat 
Published: July 2020

Abstract
Reservoir simulation is a popular tool to understand unconventional reservoirs dynamics. Applications include estimating long-term production behavior, enhancing well spacing and pad modeling efficiency, optimizing completion and stimulation of horizontal wells, and understanding production drivers that cause differences in productivity between wells. The objective of this work is to revisit fundamental concepts of reservoir simulation in unconventional reservoirs and to give several real examples that form part of an archive of lessons learnt.
Our work includes several reservoir simulation models in unconventional plays worldwide. These models are a function of the specific objective (from the 4 aforementioned applications) and reservoir type. They include structured and unstructured grid models, high- and low-resolution gridding, single porosity and dual porosity, compositional and black oil PVT, variations in the definition of complex hydraulic fractures in shale reservoirs (accounting for variations in properties that occur in time and space), and different protocols for incorporating initial water in-place as a result of hydraulic fracturing fluid.
We have encountered several challenges during this work. Some of these include: simulation model non-uniqueness, accounting for variations of reservoir properties with time and space and implications of production forecasting in volatile oils or gas condensates. Our work has brought to light important aspects of modeling unconventional reservoirs, such as changes in apparent well productivity after well shut-in or choke changes, cluster spacing, grid size and complex fracture thickness effects in horizontal wells, supercharging effects resulting from hydraulic fracture treatments, and simulation grid cell size impact on reservoir simulation cases where modeling transient flow behavior between perforation clusters. In most cases, to reduce computational time we have taken advantage of modeling a portion of the lateral and scaling up the results.
The lessons learnt continue the forum for further discussions regarding shale reservoir well and production modeling in our industry. They will provide a useful reference especially for those with little experience in unconventional reservoir simulation to better understand and develop both new and existing unconventional reservoirs.