Silveira, T. M. (Federal University of Rio de Janeiro) | Silva, W. G. (Federal University of Rio de Janeiro) | Couto, P. (Federal University of Rio de Janeiro) | Alves, J. L. (Federal University of Rio de Janeiro)
Pre-salt carbonate reservoirs are known by their huge heterogeneity and their porous system present a challenge regarding reservoir characterization, petrophysical parameters analysis and full understanding of fluid flow dynamics. Besides that, the cost of obtaining rock samples from the reservoir and the destructive nature of most experimental tests increase the interest in develop the concept of Digital Rock Physics (DRP); DRP is based on high resolution imaging and three-dimensional digitizing aiming to investigate and calculate the physical and fluid flow properties of the porous media. In this approach, this work uses X-Ray computed microtomography, digital reconstruction and image processing to achieve the 3D modeling of porous media and estimate petrophysical parameters of Pre-Salt lacustrine carbonate analog samples: coquinas from Morro do Chaves Formation, Northeast Brazil. Experimental data is used to validate the predictions. The results suggest that an important step in the rock digital reconstruction refers to the segmentation process and the high computational cost is a limiting factor to generate the porous media model in three dimensions. Despite this, the estimated physical properties are in good agreement with the previous measured experimental values and the generated 3D model will be widely used in numerical flow simulations in the next steps of this study.
Non-Newtonian fluids have been characterized over the decades, and such characterizations may be used to model a new approach in engineering disciplines. Non-Newtonian fluids are classified as non-time dependent and time-dependent fluids. This paper focuses on the non-time dependent classification, specifically pseudoplastic fluids. The ranges in these fluids allow the proposed model to be validated.
The new reservoir model accounts for non-Newtonian behavior within a double-porosity reservoir. This model demonstrates an interporosity transfer function for pseudosteady state, based on a new parameter:
We derive the partial differential equation for a non-Newtonian flow within a double porosity reservoir under pseudosteady state interporosity transfer conditions. The solution presented is for an infinite acting reservoir (assuming the corresponding initial, inner and outer conditions).
The objective of this paper is to deliver and provide tools that may help to characterize double porosity reservoir under the condition that a non-Newtonian fluid is present, and the interporosity transfer conditions between a matrix system and a fracture system are in pseudosteady-state.
In Shale plays, EUR relies almost exclusively on "primary" production with practically no account for Enhanced Oil Recovery (EOR) practices. However, many remarkable facts are sometimes considered as "anecdotic" or pointed out as outliers, rather than including them as part of a coherent explicative model. Both, included in the literature and commented by the operators, we have repeatedly found many cases reporting such "anomalous" facts such as: (i) Low liquid recoveries during flow back periods, (ii) Rapid salinization of flow back water, (iii) Higher productivities correlating with lower percent of flow back recoveries, (iv) Early oil production right after flowback starts, (v) Shales described as "thirsty" or "dehydrated" (meaning lower water saturation than expected due to its pore geometry) and (vi) the evidence of huge capillary pressures, developed and supported by well documented overpressures.
After accepting these "anomalies" as an intimate part of the behavior of these non-conventional scenarios, we get many major consequences in the way we could develop and exploit them. Thus, we propose a new methodology that consists on a novel operative sequence to enhance oil production in multi stage frac Shale Oil scenarios.
The main mechanism involves countercurrent water imbibition processes, and consists of a cyclic scheme of (i) water injection, (ii) soaking and (iii) production periods that could be repeated until capillary effects fade out. This methodology, if proven successful, means a complete shift of the current exploitation practices, probably leading to a new paradigm in the way these unconventional resources could be developed and produced.
This proposal, if proved successful, should have a paramount impact in the appraisal and economics of these types of resources development, not only improving recoveries with low cost operations to transform resources into reserves, but also leveraging operational issues such as paraffin deposition, pressure maintenance, potential acid treatments, etc.
The approach involves a de risking process in three stages (i) conceptual, (ii) theoretical and (iii) experimental (lab and field tests). This paper describes the status of development of the analysis and the findings so far, which show encouraging results to continue imrproving the technique and perform additional field testing.
Scenarios of low permeability and long transient flow periods present in tight gas reservoirs, set out a major challenge on the reserves estimations. Consequently, these cause high uncertainties in volumetric estimates of gas (OGIP) and impacts in the deployment of technical and economic strategies in most projects.
Flowing material balance equation and decline curve techniques in tight gas reservoirs, have serious drawbacks to predict the original gas in place (OGIP). However, both techniques combined yield better modeling results, as shown by Cox et. Al. The aim of the present research is to propose a method based on the Gas Production analysis (GPA) technique with the Palacio & Blasingame approximations in conjunction with pressure transient analysis for diagnostics specialized of Linear Flow, which improve the confidence in reserve estimations, specifically in early time production.
The proposed method was applied in Lajas Formation of Neuquen Basin, Argentina, where a 20% maximum error decrease is expected in the OGIP, compared with non-type curve methods to the procedures (Hyperbolic and Exponencial model) in early time production.
When permeability and porosity values are higher, the error of this methods increases. This is mainly due to the fact that infinite acting flow periods are shorter. However, in low permeability scenarios the OGIP estimation may achieve acceptable outcomes since infinite acting flow last longer.
There are many methods and tools for estimating the current water/oil (WOC) or gas/oil contact (GOC) in the reservoir. PLT and RST logs can timely monitor the production of each phase in the well and estimate fluid contacts. Material balance or numerical simulation models allow to estimate or predict the depth fluids contacts. In all cases, these tools involve a large amount of human and financial resources and in most cases their accuracy depends on the time expend to calibrate them.
This work proposes a methodology to determine the current depth of the fluid contacts, using surface measurements of the specific gravity of oil (°API) in wells. The proposed methodology is based on the principle of the compositional variation of the fluid in the reservoir and its effect of the properties of the produced fluids. Two diagnostic plots are proposed: (1) for estimating the current depth of the fluids contact at well level and (2) for predicting water breakthrough time. Some real examples of wells showing the behavior outlined in this paper will be presented to support all presented theories. Finally the proposed methodology and diagnostic plots were applied to a reservoir with proven compositional gradient to validate the proposed work.
Moridis, Nefeli (Texas A&M University) | Soltanpour, Yasser (Texas A&M University) | Medina-Cetina, Zenon (Texas A&M University) | Lee, W. John (Texas A&M University) | Blasingame, Thomas A. (Texas A&M University)
We began this research by asking "Can we use Bayes' theorem to supplement available decline models and improve the accuracy of our estimates of ultimate recovery?" This study focuses on the Eagle Ford Shale, and in particular, on oil wells in the Greater Core Eagle Ford Area. Our goal was to develop a method based on a probabilistic approach to identify, characterize, and better model well production based on standard decline models
To attempt to answer this question, we first obtained data for 68 wells in the Greater Core of the Eagle Ford Shale, Texas. As process, we eliminated the wells that did not have enough production data, wells that did not show a production decline and wells that had too much data noise, leaving eight wells. We then performed decline curve analysis (DCA) using the Modified Hyperbolic (MH) and Power-Law Exponential (PLE) models (the two most common DCA models), consisting in user-guided analysis software. Then, the Bayesian paradigm was implemented to calibrate the same two models on the same set of wells.
The primary focus of the research was the implementation of the Bayesian paradigm on the eight-well data set. We first performed a "best fit" parameter estimation using least squares optimization, which provided an optimized set of parameters for the two decline models. This was followed by using the Markov Chain Monte Carlo (MCMC) integration of the Bayesian posterior function for each model, which provided a full probabilistic description of its parameters. This allowed for the simulation of a number of likely realizations of the decline curves, from which first order statistics were computed to provide a confidence metric on the calibration of each model as applied to the production data of each well.
Results showed variation on the calibration of the MH and PLE models. The forward models (MH and PLE) overestimated the ultimate recovery in the majority of the wells compared with the Bayesian calibrations, proving that the Bayesian paradigm was able to capture a more accurate trend of the data and thus able to determine more accurate estimates of reserves.
In industry, the same decline models are used for unconventional wells as for conventional wells, even though we know that the same models may not apply. Based on the proposed results, we believe that Bayesian inference yields more accurate estimates of ultimate recovery for unconventional reservoirs than deterministic DCA methods. Moreover, it provides a measure of confidence on the prediction of production as a function of varying data and varying decline models.
Many fields in Argentina have multilayer reservoirs that require various stimulation techniques, primarily hydraulic fracturing. A variety of formations and types of reservoirs, such as conventional (mature fields) and unconventional (tight gas and shale), are the main focus in the Golfo San Jorge and Neuquén basin. The hydraulic fractures created in these basins present a variety of conditions and challenges related to depth, well architecture design, bottomhole temperature (BHT), reservoir pressure, and formation permeability.
In 2006, a pinpoint completion technique was introduced to help achieve greater efficiency and reduce time and costs associated with completions. This paper presents experiences gained using this technology and proving such versatility in different types of reservoirs.
The pinpoint technique, called hydrajet perforating annular-path treatment placement and proppant plugs for diversion (HPAP-PPD), was applied in new wells at different reservoir conditions. The history and evolution of this technique in Argentina was initiated in conventional oil reservoirs (mature fields in Golfo San Jorge) and then was introduced in the Neuquén basin in gas well completions. Throughout the last seven years, this technique has been tested and implemented in tight gas wells. More recently, it was used to improve a completion technique in a shale oil well.
This completion method allowed operators to focus treatments in desired zones using specific treatment designs based on reservoir characteristics. Several case histories are presented for different basins, formations, and reservoirs types, highlighting lessons learned and reduced completion time.
Operational execution of Fluid Sampling technologies in the logging-while-drilling (LWD) environment compared with Wireline requires a different set up and allows new operational capabilities for LWD. The objective of this paper is to identify what are the jobs operational risks, in order to select the best LWD technologies and operational approach to identify and mitigate these risks while drilling, resulting in the fastest and cleanest reservoir sample. LWD fluid sampling technology brings three new operational capabilities to this type of service: ability to select pad orientation; drilling fluid flow is required to keep the BHA energized and real time (RT) data telemetry and; capability of operating in HAHZ wellbores without additional risk. To take full advantage of these new capabilities, there must be a full understanding of the relationship between wellbore and formation, analyzing subjects such as filtrate invasion profile, borehole stability, sand production, petrophysics and LWD FE. The ability to choose pad direction, coupled with high end technologies, such as NMR and resistivity images generate important capabilities to be evaluated considering formation quality and borehole condition, allowing the selection, not only of the best depth to sample, considering petrophysical properties, but also the optimum pad direction, considering borehole conditions. Images allow the identification of drilling induced fractures, breakout, faults and thin bed, making it possible for RT interpretation for optimum pad direction, avoiding undesired features. Prior geomechanics study help identify issues that might come up during fluid sampling operation, such as breakout, sand production and borehole failure related to bedding plane. Technologies such as acoustic, NMR and images allow RT evaluation of these issues and the ability to select pad orientation and nonstop drilling fluid flowing may result in correcting these issues. Filtrate invasion profile generates complex geometries with lateral displacements and gravitational segregations. Prior study of invasion profile reservoir and drilling fluid properties, thin bed analysis and reservoir/non-reservoir interface analysis must be considered to achieve optimum operational time. This paper presents a technical and operational approach for LWD fluid sampling operations, regarding FE, geomechanics and fluid invasion profiles, which minimizes operational risk and optimizes sampling time.
Amaro, T. P. (Queiroz Galvão Exploração e Produção S.A.) | Pessoa, M. C. (Queiroz Galvão Exploração e Produção S.A.) | Cardoso-Júnior, R. A. (Universidade Federal Fluminense) | de Campos, T. M. (Pontifícia Universidade Católica do Rio de Janeiro)
The analysis and comparison of solid waste generation, transportation, treatment and final disposal data, generated during two exploratory offshore drilling campaigns (2011 and 2013) in BM-J-2 Block (Jequitinhonha Basin, Brazil) with and without the use of a temporary waste storage exclusive area for this operation aimed to verify the applicability of these two waste management operational alternatives in regions where the oil and gas exploration and production industry is not yet consolidated.
The compliance with Brazilian legal requirements, with the implementation of a Pollution Control Project according to Technical Note CGPEG / DILIC / IBAMA N° 01/11 guideline, allowed the comparision of data generated during the two drilling campaigns, even though they have been generated in different moments. Data generated during the campaigns were critically analyzed and compared using spreadsheets (dynamic tables), elaborated in Microsoft Office (version 2016), considering the need to check the profile of waste generation from both campaigns and to evaluate the effectiveness of two different management strategies implemented.
With the waste generation profile analysis for both campaigns, it was concluded that in the 2013 campaign, procedures that allowed qualitative improvements (such as the increase of the best forms of treatment and disposal and of the range of qualified suppliers for management of waste generated by the company's operations) and/or quantitative improvements (such as the decrease in the number of transportation events and the travelled distances) were adopted.
Despite the need for continuous improvement, based on the results of this study, we can conclude that the Pollution Control Project during the two f offshore drilling activity campaigns in BM-J-2 Block was effective and implemented according to the Technical Note CGPEG / DILIC / IBAMA N° 01 /11 guideline and the use of temporary storage area, although exclusive and built for the operation, is the best management strategy also in areas where the E&P industry is not yet consolidated.
Is important to highlight that for a successful implementation and operation of the storage area, the planning of the whole implementation of the Pollution Control Project needs to be minimally effective, avoiding waste loss and other related issues, fines applied by the environmental licensing agency, disengagement of the operation's workforce and difficulties for licensing future operations.
Stability of asphaltenes is affected mainly by the change in pressure and temperature within the reservoir or in production lines. Destabilized asphaltenes results in several flow assurance problems due to their higher precipitation tendency. While there are numerous studies investigating the role of pressure and temperature on asphaltenes stability, the role of reservoir components on asphaltenes stability still remains unknown.
Hence, this study investigates the effect of reservoir rock-asphaltenes interaction on asphaltenes stability. 11 different crude oil samples from all around the world and their asphaltenes were analyzed. Both n-pentane and n-heptane asphaltenes surfaces were visualized under scanning electron microscope (SEM). Inorganic (mainly salts and clays) presence was observed on asphaltenes surfaces, which might be the consequence of the reservoir rock-oil interaction. Thus the inorganic content of separated asphaltenes were investigated by mixing asphaltenes and deionized water vigorously by a centrifuge to separate the inorganic content of asphaltenes from asphaltenes’ surfaces. The supernatant of these mixtures was subjected to total dissolved solids (TDS), pH, and conductivity measurements.
The TDS level was observed high which proves the physical interaction of asphaltenes with reservoir rock and this interaction is also found to generate high conductivity mainly due to sodium salts. The electrostatic charges created in water due to inorganic content of asphaltenes were determined by zeta potential. Precipitation tendency of the colloids were found very high for most of the asphaltenes samples and they are mainly because of the presence of excessive amount of negatively charged particles. Particle sizes of those particles were also measured high which increases the chances of the particles to come together for precipitation.
This study proves the presence of electrical charges on asphaltenes surface and highlights its importance on asphaltenes stability.