bluuebunny/crossref_metadata_2025 huggingface dataset:
Public Engagement: New Approaches to Enhance Field Planning and Environmental Compliance for O&G Development
Authors: Higgins Marian , Burnett David , Kreuter Urs , Theodori Gene , Haut Richard
Published: October 2018

Studies have shown the need to engage the public early in planning new energy development ventures. Many times, this may be critical to the ultimate success of that program. Based on our previous studies of community acceptance of shale development projects, we have undertaken new studies to understand better the communities’ views of development in environmentally sensitive areas. Early interviews with key stakeholders and specially conducted focus group meetings helped previously to identify the public's perceptions of such technology and showed that favorable or unfavorable views were based mostly on pre-conceived notions of potential effects rather that factual data. Those findings have shown that a developer should actively work to increase the public's awareness about a potential project. There is a strong need for those who plan new energy development to be completely transparent and to give the public knowledgeable (and credible) information about events and developments that will impact them, not just financial gains, but environmental impacts and overall effects on community.

Recognizing that sustainable development of energy resources is a sound business strategy, some O&G companies are now incorporating public engagement as part of their business strategy. However, some companies do not. Recent activity in West Texas provides an example of how companies should and should not go about energy development projects.
Development of a Large Deep-Water Gas Field in Tanzania: Subsurface Challenges and Solutions in a Frontier Area
Authors: Haugen Einar , Solymar Sabina , Pannetier-Lescoffit Severine , Reksten Kari , Lund Ida Winsnes , Mrsic Zoran
Published: October 2018

Significant gas discoveries have been made in deep waters off the coast of Tanzania this decade. Operator Equinor (previously Statoil) with co-venturer ExxonMobil have drilled 15 exploration and appraisal wells in Block 2 about 100 km from the shore in the southern part of the country. The objective is to develop gas resources for a large LNG project. This paper focuses on the various discoveries made and the subsurface understanding gained over the last years.

The reservoirs are all deposited as turbiditic sandstones in different geologic periods (Cretaceous to Miocene), and have a long and complicated geological history. Heavy tectonic activity including development of pop-up structures along a major strike-slip system, has impacted the depositional environment. Since some of the reservoirs have significant internal faulting, methods to analyze fault transmissibility have been key. The seismic quality is generally good, and in certain reservoirs even good enough to directly use seismic inversion dataset to map the structure more accurately. The exploration and subsurface teams worked together in improving the development concept and minimizing risk.

The youngest reservoir (Miocene) has excellent reservoir properties but special challenges with shallow overburden with top reservoir 400-500 m below the seafloor. Several studies have been completed to ensure that production wells can be safely drilled and produced during reservoir depletion, and that the reservoir seal has full integrity.

In deep water oil and gas developments it is important to demonstrate large, continuous flow units with good flow properties before investment decisions. For the Block 2 gas reservoirs understanding the aquifer strength is important for designing wells so that water production can be avoided. Detailed aquifer modeling has been made for all the main reservoirs. Modelling showed risk of water production for one of the reservoirs; however, it is expected that this risk can be mitigated by placing the planned producers high on the structure.

Deep seabed canyons are present in the area and these give important constraints on drilling locations and subsea layout including the major gas pipeline to shore. The field development is planned as a subsea-to-shore development without any fixed installations offshore. To predict the dynamic performance of such a huge and complex production system, extensive flow assurance studies have been completed.
Multiple Enhanced Mechanical Property Cements Help Prevent Pre- and Post-Fracturing Gas Migration
Authors: Kutchak Kristin , Jones Paul , Van Meter Samuel
Published: October 2018

"Gas migration" has been the catch phrase of the Appalachian Basin in the northeastern part of the US for years. As demonstrated in a previous study, optimal displacement efficiency can be obtained by rotating casing during the entirety of the cement operation, providing uniform cement coverage and eliminating gas migration. However, while horizontal well lengths continue to increase, the ability to maintain rotation for the entirety of the cement operation can be severely inhibited.

Conventional cement slurries are satisfactory for the majority of wells in both the Marcellus and Utica/Point Pleasant. However, while operators are pushing the limit toward a 20,000-ft measured depth, there is a growing need to rely less on industry best practices written at the onset of shale drilling and expand engineering creativity toward implementing new technologies. With rotation off the table, a service company recommended the combined use of two highly enhanced mechanical property cement slurry technologies to bridge the technology gap from a conventional cementing solution to a more "life of the well" solution.

Historically, gas migration from either the Upper Devonian and/or the Marcellus Shale has been proven to be troublesome for the northeastern part of Pennsylvania. When the challenge cannot be addressed with historical best practices, deploying new technology on hand is necessary to achieve the goal. With the more robust functionality of a low-Portland cement design and resin composite cement slurry, the service company's design team was able to combine these two technologies to deliver a dependable barrier tailored to achieve zonal isolation. Optimizing the placement of the resin-composite-based cement slurry itself was pivotal; placement across the problem zones and above the landing point of the horizontal section was necessary. Successful elimination of both pre- and post-fracturing gas migration was achieved without casing rotation during cement slurry placement. The wells were put into production, and the operator has not had to perform any costly remediation operations because the reservoir was properly isolated by means of the primary cementing operation.

Enhanced mechanical property cements were proven to be vital for alleviating the concerns of gas migration. These cement systems help prevent Upper Devonian and Marcellus wells from being reworked because of primary cement quality post-completion.
Successful Implementation of High Viscosity Friction Reducer in Marcellus Shale Stimulation
Authors: Johnson Matt , Winkler Adam , Aften Carl , Sullivan Phil , Hill W. A. , VanGilder Criss
Published: October 2018

Throughout multiple shale plays, high viscosity friction reducers (HVFRs) have successfully placed more proppant mass with lower treating fluid volume; thus, the industry is accelerating adoption of these treating fluids. Previous published studies have included treatments in Bakken shale and Permian Basin formations.

The characteristics of the Marcellus shale make it particularly beneficial to minimize water and gel injection into the formation. At the same time, operational constraints related to smaller footprint and pad sizes in the Marcellus region make it beneficial to reduce gel hydration equipment on location. In spite of these potential benefits, application of high viscosity friction reducers has only recently begun in the Marcellus region.

One factor delaying the introduction of HVFRs into the Northeast has been the challenging waters and brines often used in treatments. This study documents the successful introduction of a brine tolerant, high viscosity friction reducer with multiple operators in the Marcellus region.

Marcellus operators compared several different friction reducer chemistries through field trials on multiple pads. Based on measurements of surface treating pressure and proppant placement, an optimum fluid system was selected that is effective in a range of water qualities and allow increased pump rate. The friction reducer was also compared to conventional gel technology based on the same method. The brine tolerant friction reducer was found to be an effective replacement for linear gel fluids and allowed reduction of equipment on location.

A brine tolerant, high viscosity friction reducer enabled treatments to be placed with increased sand loadings, higher pump rates, and decreased surface treating pressures. The fluid system was able to work with a variety of water conditions, including brines having more than 30,000 ppm chlorides. In one case the new fluid system allowed operations to entirely move away from gel chemistry and surface hydration equipment.

The study presents measured results during the frac on one of the first applications of a high viscosity friction reducer in Marcellus shale treatment.
A Statistical Engine to Model Well Operations and Evaluate Asset Performance
Authors: Gupta Supriya , Sharma Abhishek , Verma Ekansh , Abubakar Aria , Gupta Sidd
Published: October 2018

Holistic understanding of well operations can play a key role in optimization and maintenance of assets. The traditional process for understanding well operations mainly involves fitting a curve through all of the historical production data and extending the curve to forecast production without modeling the stochastic nature of production history, considering impact of any well interventions, or feeding any a priori information into curve-fitting workflows. This leads to unreliable production and reserves estimates which, in turn, impact the strategy and planning process for asset management. A novel workflow was developed learns the production characteristics of a well through a statistical framework using principles of signal processing and Bayesian inferences. Using this workflow, high-fidelity empirical production performance forecasts can be obtained for all the wells in the asset in an automated fashion. This novel workflow aims to significantly simplify interpretation of well operations, reduce the turnaround time for analyzing and modeling well performance, and improve the quality of reserves estimates.
Enhanced Oil Recovery in Eagle Ford: Opportunities Using Huff-n-Puff Technique in Unconventional Reservoirs
Authors: Pankaj Piyush , Mukisa Herman , Solovyeva Irina , Xue Han
Published: October 2018

Although hydraulic fracturing in liquid-rich unconventional reservoirs (LUR) has become a norm, the recovery factor continues to be low. Use of enhanced oil recovery (EOR) techniques in LUR has recently become more popular to improve the recovery. The objective of this study is to numerically investigate the advantages and disadvantages of the application of the CO2 huff-n-puff technique in LUR formations having complex fracture networks.

The study explores the fluid flow mechanisms for oil recovery in a naturally fractured reservoir. A calibrated 3D mechanical earth model with geomechanical and petrophysical properties from the Eagle Ford was used for the study. A complex hydraulic fracture model was used to simulate the hydraulic fracture, proppant, and fluid distribution around the wellbore. Numerical reservoir simulation on perpendicular bisection (PEBI) grids was used to capture the permeability, porosity, and conductivity distribution due to the proppants in the hydraulic fractures. The CO2 huff-n-puff technique using numerical reservoir simulation was used to determine the well performance and recovery factor arising from reservoir fluid viscosity reduction and gas expansion. The effect of fluid thermodynamics to recovery systems in the low-permeability reservoir medium was fully captured in this approach. An equation of state prepared for simulating the CO2 impact on the oil was prepared with correlating the collected downhole oil sample.

The numerical reservoir simulation study coupled with the complex fracture simulation model presents insights into a new means to improve the recovery factor (RF) in LUR through the injection of CO2. Such EOR method would be critical to increase the long-term economic benefits. The study demonstrates that that infill well requirements can be mitigated if the EOR method of huff-n-puff is utilized in cyclic modes over various time periods of production. Up to 9% extra RF was observed when the CO2 huff-n-puff technique was used as compared to production dependent only on hydraulic fracture stimulation. Parametric sensitivity on job sizes and start timing of EOR in a producing well was used to evaluate the RF. However, the hydraulic fracture geometry and the created footprint along with the time of injection have a larger effect in improving the EOR effectiveness.

The methodology demonstrates the simulation of EOR methods in unconventional reservoirs for economic assessment. The workflow demonstrates modeling CO2 flooding as an EOR technique on the full wellbore level with complex hydraulic fracture geometry. The approach can be applied to unconventional formations in other basins to improve the recovery factor.
Decision-Focused Optimization: Asking the Right Questions About Well-Spacing
Authors: Hassen Ryan A. , Fulford David S. , Burrows Clayton T. , Starley Gregory P.
Published: October 2018

Engineers and leaders who must decide on development strategies for unconventional resource projects face a challenging design problem. While we must make decisions on well and completion design, including well-spacing in three-dimensions, the complexity of the physical system and the interactions between these parameters can become overwhelming. The technical optimization problem can be difficult; however, asking the right questions can make the business decision clearer than it first appears.

The typical approach to design optimization problems is to build models, with a tendency toward including an ever-increasing number of parameters to describe the system in exhaustive detail. However, our uncertainty in the model parameters often makes it impossible to identify the true optimum. In this work, we focus instead on reducing the number of model parameters and capturing the impact of these critical uncertainties on our business decisions. This allows us to answer the right questions in order to define and choose the best well-spacing strategy.

For well-spacing optimization, a critical uncertainty is the relationship between the chosen well-spacing and the potential well-performance degradation, in terms of estimated ultimate recovery (EUR) and initial production (IP). Rather than attempting to describe fracture geometry and well interference from a mechanistic standpoint, we introduce a lumped parameter, the shared reservoir (SR) factor, to account for this complex relationship. The parameter distribution may be calibrated to (a) well results in a play, (b) well results in carefully selected analogue plays, or (c) simulated well results from probabilistic analyses. An example of a Monte-Carlo simulation using the uncertainty of the SR factor, as well as the mean EUR and IP, highlights the utility of the method. We also illustrate how the spacing decision impacts key risk and financial metrics, including the expected monetary value of the project, the probability of regretting the decision, and the probability of commercial success of the project.

The shared reservoir factor is proposed to capture the complex relationships between the well-spacing decision and the EUR and IP that result from this decision. Using the shared reservoir factor, we can develop simple stochastic models to clarify an otherwise frustratingly complex optimization problem.
Proppant Transport Behavior in Inclined Versus Vertical Hydraulic Fractures: An Experimental Study
Authors: Ba Geri Mohammed , Imqam Abdulmohsin , Dunn-Norman Shari
Published: October 2018

Understanding proppant transport in complex fracture systems plays an essential role in determining propped fracture area, fracture conductivity, and their impact on well productivity and economics. Despite extensive, historical work that has studied proppant transport in vertical fractures, very limited investigation exists regarding proppant transport appraisal in inclined hydraulic fractures. This study provides a better understanding of proppant distribution in inclined hydraulic fractures.

Proppant transport is governed by several factors such as varying of slurry velocity, fracture geometry, proppant size, and proppant concentration. The main purpose of this experimental study is to evaluate the proppant settling and transport and to determine fracture propped area as a function of the key proppant transport factors in different inclined fracture geometry. Low viscosity fracture fluid (slickwater) was used with different particle sizes: 20/40, 40/70, 100- mesh ceramic proppant. To mimic slurry transport in hydraulic fracturing treatments, a 2 ft. × 2 ft. fracture slot model was constructed with gap of 0.25 in. representing the fracture width. Orientation of the fracture model can be adjusted from vertical to inclined positions. Four injection points perpendicular to the wellbore were used to simulate injection through multiple perforations, in addition to single point injection scenarios.

Equilibrium dune height (EDL) is expressed in three regions (near the wellbore, in the center of the fracture, and at the fracture tip) for created fractures. Variations in EDL as a function of the number of perforations that contributed during proppant transport are compared for both vertical and inclined fractures.

Experimental results show that both fracture inclination and number of contributing perforations impact EDL and propped fracture area. Inclination of fractures can have significant impact on proppant transport due to the friction or contact force, which comes from the fracture wall. This friction impacts settling velocity of the proppant and impacts the proppant distribution efficiency inside the fracture. Increasing fracture inclination angle increases fracture propped area. Finally, this work observed that number and perforations and their position play an important role in proppant transport, particularly in inclined fractures.
Modeling Geopressures in a Tight Gas Reservoir, An Argentinean Case
Authors: Guerra Julian , Olmos Martin de , Szelagowski Manuel , Zurita Pablo Ibañez
Published: October 2018

Geopressures modeling has become a critical task in unconventional plays since the high pore pressures found in some areas makes drilling and completion operations particularly challenging. This field study helped to quantify the pore pressure anomalies and understanding the overpressure mechanisms acting in the tight gas reservoir of Rio Neuquen field. To achieve this objective a pore pressure model was built based on seismic attributes and multi well data analysis. This model also helped to establish possible relationships between reservoir performance and those pore pressure anomalies.

The mathematical model used seismic velocities from PSDM tomography and simultaneous inversion for establishing relationships between the elastic rock response and pore pressure, through a series of effective stress-velocity transforms. The model also considers a multi variable analysis to account for other variables affecting seismic response, including porosity, VSH and effective stress, like that proposed by Sayers (2003). Field data from several wells was used to tie the seismic velocities to well logs, while laboratory tests and pressure measurements were used as calibration points for the model, supporting the results of the study. The analysis showed that interval velocities from seismic inversion led to a more representative and accurate pore pressure model than that obtained from the PSDM velocities. The analysis showed that velocity reversals from seismic had a strong stress influence while as confirmed later by ultrasonic lab test analysis and observed pressure data. There were also some lithological and porosity effects in the elastic response of seismic, as evidenced by well logs. This, however, could not be modeled at field scale due to limitations in the available 3D seismic data.

Pore pressure anomalies are expected to be highly influenced by the presence of a nearby overpressurized source rock. The study suggests indeed that that multiple type II overpressure mechanisms can be present in the area, including lateral transfer, HC generation and tectonic load. The model showed that the pressure anomalies are higher as closer is the reservoir to the source rock. Four new wells drilled in the recent campaign probed the accuracy and robustness of the pore pressure predictions.

This work is an excellent case study that shows how pore pressure can be modeled in some tight sands that exhibits a stress sensitive behavior. The pore pressure model helped to evaluate not only gas reserves but also sweet spots, making the 3D pore pressure prediction a powerful tool for exploration, drilling and field development planning.
Smart Expandable Polymer Cement Additive to Improve Zonal Isolation
Authors: Santos Livio , Dahi Taleghani Arash , Li Guoqiang
Published: October 2018

One of the critical issues that might happen in some oil and gas wells is the failure of the cement sheaths and its debonding from the casing string. Cement shrinkage during setting is regarded as one of the main causes behind formation of microannulus cracks. In this paper, a new class of polymer-based expandable additives is presented in the form of fibers to address shrinkage and debonding issues in the subsurface. The proposed fiber additives are made from shape memory polymers. These fibers expand upon exposure to temperatures above certain limits; which is selected to be below the temperature of the cementing zone. In this situation, the expansion occurs before the cement setting but after its placement. If the expansion occurs after cement setting, it may lead to microfractures. As a result of the controlled expansion of the cement paste, the creation of channels and fluid migration can be minimized while maintaining the mechanical properties required for cement integrity. Considering the inert property of the proposed additive, the cement water ratio and its chemical properties do not change. The cement expansion, fluid loss, gel strength, compressive strength, and tensile strength of the samples containing these fibers are examined by destructive and non-destructive methods and presented here. The proposed class of expandable additives can help the operators reach sustainable well integrity by improving the bonding between the cement and casing.
Vaca Muerta Numerical Simulation: A Warning in Compositional Modelling
Authors: Bosco Sergio , Suarez Mariano , Savoy Elisabet
Published: October 2018

The paper highlights the limitations in the use of cubic equations of state (CEOS), for modelling reservoir behavior of liquid phase (black and volatile oil), in highly undersaturated reservoirs. This is important in high shrinkage volatile oils for which complex dependence of fluid behavior with composition is found.

Vaca Muerta formation fluids run from medium black oils to very dry gas, according to source rock maturity. High shrinkage volatile oil and very rich gas condensate are found and compositional variation is areally continuous. Despite this huge difference in fluid nature, where saturation pressures are present, more than 200 kg/cm2 undersaturation are reported.

Due to the complex dependence of fluid behavior with composition for near critical gas condensate and volatile oil, the use of compositional modelling is mandatory.

Reservoir pressure evolution with production and recovery calculations rely largely on compressibility, which itself is not a fitting parameter for usual CEOS. A very good fit for liquid volumes in CEOS, i.e. less than 5 % maximum error in volume, leads to unacceptable differences in compressibility (over 30 %).

To compare the consequences in production of this difference, a black oil model was run with different fluid scenarios: one with experimental compressibility and other two with compressibility obtained from CEOS. In the model, all formation, fracture and other fluid properties are the same, as well as the BHP imposed.

The results from numerical simulation show that rates and cumulative production from CEOS compressibility scenarios are half of those obtained with experimental compressibility. Part of this difference may be explained from fluid behavior alone, and the remaining is due to poral compressibility and fracture conductivities related to the different trends in pressure.

The CEOS are the only ones implemented up to now in the commercially available compositional numerical simulators. In this paper we show the limitation of these CEOS for the description of highly undersaturated volatile oil reservoirs.
Field Development Optimization Through Integrated Geosciences and Engineering Analysis
Authors: Hren Agustin , Exler Victor Ariel , Peacock Horacio , Schmidt Roberto , Pellicer Marcelo Daniel , Lamberghini Lucia , Gait Jorge
Published: October 2018

Lindero Atravesado field is located in Neuquen, western Argentina. It has been under development since 2012. Originally, its development was focused on conventional formations (Quintuco, Sierras Blancas and Lotena), considering the Punta Rosada and Lajas formations as geological traps. Development is now focused on these traps, especially in the northwest region the field, called the Lindero Atravesado Occidental. Fundamental challenges in the Occidental region of the field include optimum fluid engineering, avoiding shear-sensitive fluid systems, high PAD percentage and safe operational efficiency in deep HPHT wells.

However, original frac designs were optimized through a traditional cycle of design and pressure-matching evaluations using a conventional frac simulator. Obtained fracture geometries were bounded in length and a considerable height growth was observed. Other studies used microseismic, sonic profiles or traceable sands, and showed fractures contained in height and longer fracture lengths than those obtained with the traditional adjusted model.

A fracturing model coupled with microseismic interpretation allowed a better characterization of fracture geometry, vertical covering, effective production fracture length and drainage area efficiency, based on numerical production simulations and matching. The last point will have a direct impact on well spacing and future selection of in-fill locations.

This paper will discuss a fully integrated approach for field planning optimization, starting with geosciences characterization, workover, stimulation and production history matching, with a direct impact on well gridding and estimated ultimate recovery (EUR) per well.
Experience in Lateral Well and Perf Cluster Spacing for Shale Dry Gas
Authors: Chiarandini Fabio David
Published: October 2018

The objective of this work is to present an integrated methodology/workflow for optimizing lateral well spacing and fracture spacing for unconventional reservoirs based on multiple experience in Marcellus shale gas development. Optimal well plans and completion designs, based on geology and reservoir characterization, are key elements in developing economic projects. Well performance and reserves at a pad level can be improved thought coordinated efforts from multi-functional disciplines.

Workflow incorporates data integration and main analysis to be performed from all involved disciplines. Main disciplines are geology, reservoir and production engineering, drilling and completions teams, decision and economic evaluation and cost assurance process. A full set of reservoir modeling, economic analysis tools are described in the document. Workflow is optimized with a loop, where main routine and non-routine surveillance is used mainly for interference analysis and further optimization on both spacing for the factory-style development.

Reservoir simulation fed into two separate workflows. One is a single pad economic model and or DOE which incorporates decision analysis techniques. The other is a portfolio analysis with pads scheduled to fill a midstream capacity constraint through time. Both cases balance the increased capital costs against accelerated and increased production. The portfolio analysis tool is useful in understanding impacts of tighter well lateral and cluster spacing, particularly how they influenced capital costs over time. Additionally, results are compared with analog data and competitor analysis.

Methodology was field tested. Workflow application demonstrates that optimum lateral well spacing and cluster spacing in dry gas core area would have a positive impact on EUR (estimated ultimate recovery) at a pad level. Also, pad drilling and Completion optimizations provide increased NPV (net present value) and incremental DPI (discount profit investment) ratio.

The experience in lateral well and perf cluster spacing for shale dry gas for geometric completions is an example of how to manage uncertainty through cross-functional collaboration.

Workflow can be used as inputs in pilot test for well spacing and as a process to justify surveillance needs using value of information techniques.
Type Curves for Vaca Muerta Horizontal Wells
Authors: Johanis Pablo Esteban
Published: October 2018

The increasing number of drilled, completed, and produced horizontal wells in Vaca Muerta enables strengthening the generation of its type curves. The samples can be categorized by produced fluid, landing zone, and eventually by other criteria, reaching statistical significance and, thereby, enabling the preparation of type curves specific to each criterion.

Public domain monthly production data, combined with directional, completion, and hydraulic fracturing records related to horizontal wells in Vaca Muerta, were gathered, building a database that as of December 2017, included 254 wells. Each well was classified according to fluid produced, landing zone, and well location relative to slope breaks of progradant facies. The monthly produced volumes are expressed in equivalent barrels of oil and normalized to 1,000 m of stimulated lateral length.

For each class considered, percentiles 90, 50, and 10 of a recomputed monthly series were calculated, as well as the average. The series best-fit theoretical curves were generated and are proposed as type curves.

More than 200 new entries were added to a legacy database that had been used to estimate normalized standard production and appraise stimulation trends. In this way, the data sample reached greater statistical significance and included a longer series of monthly production data, making it possible to obtain production type curves with smaller deviation and more robust means and averages. Progress was made in the discrimination of the entire set of horizontal wells in Vaca Muerta by preparing type curves for wells producing black oil, intermediate wet fluids, and dry gas. Production accumulations increase from one production type to the next in the order listed.

Relevant to landing zone criteria, discriminated type curves are presented for the "kitchen" (basal section of the formation, which reaches the highest organic and shale content)," the "organic" level (inmediate overlaying section of high organic content), and the lower and the upper prograding facies (shaly limestone sequences in the middle and upper sections of the formation). Particularly for the oil-producing wells, the type curves reveal the increased production in the "kitchen" and upper progradant levels.

The elaboration of best-fit curves to the series of typical P90, P50, and P10 data, with its generatrix algorithm, provides a simple aid to approximate production estimates and economic evaluation of projects.
Completion Efficiency Evaluation in Horizontal Wells and its Importance in Vaca Muerta Formation
Authors: Moreyra Juan Domingo , Palacios Ricardo
Published: October 2018

In Argentina, unconventional reservoir development learning processes have been continuously advancing, specially lowering project costs in Vaca Muerta's different zones, light oil, gas-condensate and dry gas. However, the actual international oil and gas prices are forcing companies to search for additional improvements to keep on developing these fields.

Vaca Muerta Oil and gas potential with big pay thickness requires the review of completion efficiency and its incidence on initial hydrocarbons production in order to improve the project cash flow.

The analysis should be focused on horizontal wells-orthogonal fractures interface which, in Argentina, has not been properly evaluated, leading us to underestimate the production loss by using the status quo of approved technologies for our projects.

Big thicknesses increase the pressure loss effects due to flow convergence from the fracture into the well, to which we have to add the near wellbore bottleneck causing a conductivity reduction due to inappropriate final concentration design, over flush and proppant grain size and quality that are not capable of holding the confining pressure, in special in some of the completion technologies.

In dry gas and gas-condensate reservoirs, non-Darcy effects and condensate accumulation in the SRV when pressure drops below the dew point, are also influenced by an inappropriate completion.

Vaca Muerta over pressure forces us to pay attention to plays whit high production due better reservoir characteristics and SRV quality induced by fracturing.

Interfaces must be designed to support such high pressures and maintain a good fracture conductivity. Technology review and selection is strongly recommended, in special in those where treatment is divided into multiple fracturing in different clusters with over flush to clean the well and/or displace guns/plugs and ball fractures between stages.

Benefits from obtaining bigger and more stable SRV through new microproppant technologies and longer horizontal wells, will not be appreciated if fractures-wellbore interfaces are not improved allowing a better fluids evacuation into the wellbore by reducing restrictions to flow. At the same time, available literature shows dissimilar results when looking to improve cash flow through refracturing depleted wells.

The purpose of this article is to show the importance of including the evaluation of production loss magnitude and its incidence on the project cash flow. This will allow considering different completion strategies on each project, some of them already available. Changes in fracture design and proppant quality will lead to a better and more stable fracture-wellbore interface.
Drilling Horizontal Well of 3200m Lateral Length in Vaca Muerta Formation
Authors: Medina Jonatan , Salcedo Gervasio Jose , Olave Sergio Eduardo
Published: October 2018

OBJECTIVES

At a time when the demand for energy is growing in Argentina, operators are seeking to improve the profitability of unconventional oilfields by drilling wells with longer lateral lengths (up to 3200 meter), allowing a larger area to be drained by single wellbore, minimizing overall development cost.

This paper outlines methods and resources used to drill this long lateral well along with the limitations that arose during the planning and execution phase.

METHODS, PROCEDURES, PROCESES

Currently the development of the unconventional oilfield in the Loma Campana and El Orejano oil areas are established with wellbore design of 3 casing strings, drilling the production zone (Vaca Muerta) in an open hole of 6-1/8" and completing it with 5" casing; achieving horizontal lengths between 2400 m to 2600 m with a maximum of 2715 m.

The current configuration of these types of wells is in a technical limit stage, due to the maximum hydraulic power that the available drilling equipment possesses and the loss of efficiency with its consequent increase in costs in the completion stage. It is for this reason and looking to increase the number of fracture stages per well, that the construction of a well of robust architecture and greater extension was considered.

RESULTS, OBSERVATIONS, CONCLUSIONS

The design change contemplated 3 casing of higher diameters 13 3/8," 9 5/8" and production section in 5 ½". This design requires drilling production open hole section in 8-½" diameter. This allowed to increase the lateral length to 3200 m, avoided reaching the hydraulic power limit of the drilling equipment and maintained the same design of stimulation while preserving the efficiency.

ADITIONAL INFORMATION

The presentation of the paper consists of the technical feasibility analysis, contemplating the uncertainties regarding drilling fluid hydraulic behavior, torque & drag, the operational results of the experience, and the resulting cost analysis.
A Multiscale Approach to Simulation of Fluid Flow in Tight Porous Media
Authors: Giro Ronaldo , Bryant Peter William , Carneiro Queiroz da Silva Guilherme , Neumann Rodrigo F. , Engel Michael , Steiner Mathias B.
Published: October 2018

Recently the world has seen tremendous growth in oil and gas production from unconventional reservoirs, such as tight-gas sands, gas and oil shales, and heavy oil and tar sands. This growth can be attributed in part to technological developments in fracturing and stimulating well production, and in part to the availability of oil and gas resources in shale. Around 75% of the sedimentary rocks on earth are clastic nanoporous rocks, which are often referred to as "shales". These shales contain most of the world's oil and probably gas resources as well, but only a small fraction can be recovered using the latest technology – typically around 5% for oil and 20% for gas. What seems to be missing is an understanding of the fundamental interactions between fluids and rock surfaces, and of the dynamics of fluids in pores with sizes ranging from a few nanometers (10−9m) to micrometers (10−6m). Filling these gaps in our knowledge will help to develop improved recovery strategies and better prediction of production.

Here we present a multiscale simulation approach meant to bridge these gaps. All Atom Classical Molecular Dynamics (AAMD), a simulation method at the scale of atoms and molecules, is used to tune parameters used in Many-Body Dissipative Particle Dynamics (MDPD), which is a mesoscale simulation method. In nanopores, a majority of the fluid interacts with the rock surface and therefore cannot be treated as bulk fluid. To capture resulting phenomena, a low level of coarse-graining was used for MDPD. This, however, limits the domain of two-fluid MDPD simulations to a single capillary. To reach the scale of true porous media, we extract parameters describing the dynamic effects of fluid-fluid interface shapes on capillary pressures, and these are used in a dynamic capillary network simulation of fluids moving through pore spaces.

Results from MDPD simulations show the extraction of dynamic variables, such as dynamic contact angle and capillary pressure as a function of speed and pore diameter, to feed a capillary network model. The dynamic network model results then reveal how modifying the molecular interactions manifests at the pore scale.

With our hierarchical multiscale approach, we can bridge the gaps from molecular-level, chemical phenomena up to flow in porous media in a physically and thermodynamically consistent manner and with a minimum of unknown parameters. We can thus investigate not only if but why and how EOR strategies for shale succeed or fail.
Pressure Measurements Challenges in Low Permeability Reservoirs of Neuquén Basin, Argentina
Authors: Bianchi Federico , Heine Sebastián , Carrizo Páez Nicolás , Bosco Sergio , Bach Roberto
Published: October 2018

This work discusses reservoir pressure gathering relevance in tight gas sands description. Data validation and interpretation procedures are outlined, as well as the impact of using this kind of data in reservoir characterization and optimum completion design.

A workflow to gather reservoir pressure values within an acceptable certainty range for the description of these low permeability reservoirs is presented. The proposed methodology is based on the analysis of historical data obtained according to traditional standards, with the aim of improving the pressure data acquisition efficiency.

The workflow considers the characteristics of most of the commercially available tools (i.e. snorkel geometry and size, flow rate ranges, etc.). Optimum zone selection and tool placement points based in log interpretation is also described.

The proposed workflow proved to be helpful in optimizing pressure data obtained through wireline formation testers. Data are in good agreement with pressures estimated by DFIT. These results encourage the continuous improvement of the technic.

In addition, some conclusions were drawn from the analysis of the DFITs obtained.

From the data analyzed, the tight sands of Cuyo Group can be best described as low porosity – low permeability reservoirs, in the micro Darcy (μD) range. Deeper zones can reach pressures and temperatures of up to 80 MPa (11600 psi) and 165°C (HPHT). Both normally and overpressurized sands can be found.

We propose a workflow to guide pressure acquisition with formation tester, to deal with the challenge of low permeability sands. Even though the results are presented in relatively wide ranges, those are suitable for better reservoir description and well completions.
Unconventional EOR: Field Tests Results in Vaca Muerta Shale Play: A Capillary Based Improved Oil Recovery Case Study for Shale/Tight Oil Scenarios.
Authors: Bodini Santiago Alejandro , Forni Luis Pablo , Tuero Fernando , Crotti Marcelo Alejandro , Labayen Inés Lidia
Published: October 2018

In Shale plays, EURs relay almost exclusively on "primary" production with practically no account for Enhanced Oil Recovery (EOR) practices. However, many recent works show the feasibility of using different techniques to improve the well's EUR by means of some kind of assistance. Lean gas, CO2 and water injection, mostly in a huff-n-puff manner, seem to lead the industry's most accepted EOR methodologies in ultra-tight (shale) formations. Conceptual, theoretical and experimental work has been made in the water huff-n-puff arena including lab and field work and documented in previous work published by the authors. The methodology consists on a novel operative sequence to enhance oil production in multi-stage fractured Tight/Shale Oil scenarios involving countercurrent water imbibition processes and consists of a cyclic scheme of (i) high pressure water injection, (ii) soaking and a (iii) production period. These cycles could be repeated until capillary effects fade out. These phenomena, which should occur in areas where a substantial portion of the shale matrix contains water-wet effective porosity, could explain some anomalous behaviors such as the low water recoveries observed in many cases, rapid salinization of the flow-back water and the rapid appearance of hydrocarbons at early flow-back times, when no substantial % of the injected water is yet recovered.

This work shares the partial results of the second field test performed in the Vaca Muerta resource play, implemented on a vertical, three-stage well in the black oil window, similar to the first field experience from previous work. The test design was modified (i.e. lower water volumes and alternation of injection and shut-in periods) based on the insights gained in previous tests, to minimize the test complexity, costs and to extract additional information from the transients. The results of this new field test showed that it was possible to inject significant water volumes without reaching original fracturing pressure and without damaging the fracture network productivity. Compared to previous tests, the surface and downhole operations were simpler and inexpensive. Partial results were encouraging, as the pre-test oil rates were recovered and even slightly improved with less than 40% of the injected water volumes recovered. Despite this, due to the shut in periods included and operative issues, in this particular trial, oil rates were not as instantaneous and as important yet, as to compensate for the cumulative oil losses during these shut-ins.
Spatial Distribution of Mechanical Properties of the Late Ordovician Glaciogenic Sandstones, SW Saudi Arabia
Authors: Benaafi Mohammed , Al-Shaibani Abdulaziz
Published: October 2018

The Late Ordovician Sanamah Formation of the Wajid Group, exposed in Wadi Al-Dawasir area, southwest Saudi Arabia, is an analogue of the late Ordovician tight gas sandstone reservoirs in Rub’ Al- Khali Basin. Sanamah Formation consists mainly of glacial origin sandstones and conglomerates deposited in Paleo-valleys. The Formation is divided into three lithological units from the bottom up, massive to cross-bedded conglomeratic sandstone and conglomerate (S1), massive to cross-bedded coarse-grained sandstone (S2), and siltstone to medium-grained sandstone (S3). The three units (S1, S2, and S3) are the proximal, medial, and distal outwash facies, respectively. This study aims to investigate the vertical and lateral variations of the mechanical properties (Schmidt hammer rebound (R), unconfined compressive strength (UCS), Young’s modulus (E), and Poisson’s ratio (V)) of the three lithological units of Sanamah Formation, and define their mechanical layers. The strength of the studied sandstone was measured in the field using Schmidt hammer rebound (R), and the sedimentology and stratigraphy were described in detail. Unconfined compressive strength (UCS), Young’ modulus (E), and Poisson’s ratio (v) were measured in the laboratory. Petrography study conducted to delineate the mineral composition and diagenetic features (e.g. type and amount of cement materials) of the studied formation. The entire sequence of Sanamah Formation subdivides vertically into three major mechanical layers (MS1, MS2, and MS3), which correspond to the proximal (S1), medial (S2), and distal (S3) outwash facies units, respectively. The increase in the strength values was found to be associated with a decrease in the grain size and increase in the cementation degree of the studied sandstone. Therefore, the vertical and lateral distribution of the mechanical layers of the studied formation is believed to be controlled by the lithological and diagenetic alterations. In the lateral extent, the mechanical layers are not consistent with lithological boundaries, whereas, the proximal facies (S1) in the southern part of Wadi Al-Dawasir quadrangle can be mechanically correlated with the medial facies (S2) in the northern part. This lateral crossing of the mechanical layer over lithological boundaries is probably related to the lateral change in the sandstone diagenesis. Understanding the vertical and lateral changes of outwash facies of late Ordovician Sanamah Formation along with its diagenetic alterations can help to predict the mechanical behavior of the equivalent sandstone reservoir in Rub’ Al-Khali Basin. Thus, the result of this study will help to enhance hydrocarbon exploration from the tight gas sandstone reservoirs in Rub’ Al-Khali Basin