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.
This study focusses on the impact of wettability alteration of reservoir clays on the overall efficiency of Steam Assisted Gravity Drainage (SAGD). Samples from two SAGD experiments were investigatedSAGD1, consisting of kaolinite in the oil-sand packing and SAGD2, consisting of a mixture of kaolinite (90 wt%) and illite (10 wt%). The residual oil saturation from two different zones (inside steam chamber and steam chamber edge) from each SAGD experiment was determined from spent rock samples. Series of systematic optical microscopy analyses were carried out on clay-sand and clay-sand-asphaltene mixtures under steam and water exposure to represent the inside steam chamber zone and steam chamber edge, respectively. The higher residual oil saturation for SAGD2 was associated with the wettability alteration of illite in the reservoir at the steam chamber edge, leading to significant illite-asphaltene association. The pore-bridging property of illite was also observed, adversely affecting reservoir permeability. Kaolinite-asphaltene interactions in the presence of liquid water, on the other hand, were found to be temporary and not binding. Our findings suggest that wettability of clays plays an important role in determining the efficiency of SAGD process, controlled mainly by the polar asphaltene fractions in bitumen reservoirs with high asphaltene concentrations.
The Vaca Muerta shale has been developed for oil and gas production since 2010 and to date nearly 500 wells have been drilled. The large amount of static and dynamic information from these wells has enabled fracture design and production strategy optimization. This paper details the methodology used to integrate all available data in 3D models, in order to understand the impact of rock properties in the production.
The model was simulated using a commercial reservoir simulator, showing that hydraulic fractures are acting as a dual porosity system with a large conductivity (~10 D) connecting a low permeability matrix (~100 nD).
We studied multiple wells in the history match (HM), using separator pressure and choke size as the control variables for the wells, and rates and pressures as comparison variables. A multi-segmented well approach was used to describe the pressure drop inside the well, and a vertical lift performance (VLP) table to describe the flow from the tubing all along to the separator including the wellhead choke.
The static model included the seismic interpretation, stratigraphic framework, geomechanical and petrophysical characterization. Rock permeability, initial pore pressure and total fracture pore volume were calibrated with field measurements used as constraints in the HM process.
Fracture conductivity degradation was introduced in the model to explain observed changes in the wells productivity. Laboratory tests are being designed to validate these hypotheses.
We established early in the project that individual well HM were not unique. It was only through the HM of multiple wells that we were able to reduce the range of uncertainties affecting well performance (matrix permeability, initial water saturation and fracture height). This has given us a more reliable tool to obtain ultimate recovery estimation ranges.
The described model showed a good prediction of a well with water lift problems, giving an accurate forecast for the incremental gas rate after a tubing diameter change. We concluded that the multi-segmented well model is a good representation of the water hold-up fraction behavior.
This methodology enables us to integrate all the knowledge of the subsurface into a model that can be run in short simulation time (~30 minutes), allowing us to iterate quickly during the HM process. The model can be run for single wells or multiple wells and is flexible to adapt for new areas.
We plan to use this methodology to design and monitor pilots in new blocks and to evaluate different development plans for existing projects.
Vaca Muerta Formation in Neuquén Basin, Argentina, is one of the great worldwide promises given its potential as a non-conventional reservoir. Because of the intrinsic heterogeneity and low permeability, hydraulic fracturing is a required operation to stimulate the reservoir for better production. Simulation becomes a desirable tool to make fractures more efficient and get predictable outcomes. For this purpose, a 3D finite element analysis is performed using ADINA software to model reservoir response during the hydraulic fracturing process.
This iterative, fully coupled model uses fluid structure interaction (FSI), porous elastic media and stratified materials with transversely isotropic (TI) properties. The allowed fracture distribution is proposed beforehand. A cohesive model is added via non linear springs placed along the fracture proposed path. Material models are calibrated using data from well logs and microseismics taken from one well located in the field. All the information obtained from that well is then filtered for a particular region of interest in depth, determined by the mechanical properties observed.
Regarding the calculation procedure, as initial condition for the stimulated reservoir volume (SRV) the stress strain state measured in the field is adopted. Then hydraulic fracture process is simulated pumping fluid through punched holes and then fracture opening is analyzed, based on nodes displacement along the proposed path, to characterize fracture's opening and extension. The resulting state of stress developed after the fracture is updated at every calculation step. Key information such as resulting pore pressure and effective stresses can be easily computed along the fracturing process.
Once obtained results are compared to analytical solutions and experimental data obtained from fractures performed in similar soil conditions with good agreement. The developed model can tackle a variety of reservoir volumes, considering stratification, geomechanical properties, fracture fluid, fracture paths and the initial state of stress. Natural cracks can be added in a rather simple fashion by adding fractures to the proposed distribution with adequate fracture strengths.
Cold Heavy Oil Production with Sand (CHOPS) is widely used as a primary non-thermal production technique in thin heavy oil reservoirs in Western Canada and the Orinoco Heavy Oil Belt in Venezuela. Several solvent and hybrid steam/solvent schemes have been proposed to increase the recovery factor from these deposits. Development of the complex wormhole networks renders the scalability of these processes from laboratory measurements to field applications challenging. In this paper, numerical simulation is used to analyze how scaling of solvent transport and dispersion would vary with developed wormhole characteristics. It proposes a practical workflow to a scale up these mechanisms for field-scale simulation.
First, a series of mechanistic compositional simulation models at the lab scale is constructed to model a cyclic solvent injection scheme (CSI). These models are calibrated against experimental measurements of solvent diffusion measured in porous media. Next, a set of detailed high-resolution (fine-scale) simulation models, where both matrix and high-permeability wormholes (modeled as fractal networks) are represented explicitly in the computational domain, is constructed to model how the solvent propagates away from the wormholes and into the bypassed matrix. Flows of solvent and oil in the matrix and wormholes are directly simulated. Following this, a dual-permeability approach is adopted to facilitate the scale-up analysis, where wormhole intensity is correlated to shape factor and apparent dispersivity. Characteristics at different averaging scales (i.e. scale-up level) are examined. Field-scale simulation are constructed using average petrophysical and fluid properties extracted from several CHOPS reservoirs in Saskatchewan, which are, to some extent, similar to those found in the Orinoco Belt. The initial conditions in terms of fluid saturations, pressure distribution and wormhole development are representative of those commonly encountered at the end of CHOPS.
Solvent transport and mixing in the wormhole networks can be captured by parameters such as shape factor and apparent dispersivity in an equivalent coarse-scale dual-permeability system. Effective dispersivity increases with averaging scale and wormhole intensity. Considering identical surface solvent injection rate, effective dispersivity would enhance oil production and reduce gas production due to an increase in mixing between solvent and oil. Several solvent injection blends are evaluated to maximize recovery efficiency.
Field-scale simulations are typically performed with grid block sizes that are much larger than the wormhole scale, and numerical analysis is often performed by arbitrary adjustment of dispersivity. This work offers a practical way to scale up solvent transport mechanisms in post-CHOPS applications. It facilitates more efficient and accurate assessment of solvent transport from lab measurements to field applications. This work serves as a starting point for formulating a systematic workflow to simulate solvent processes in wormhole networks that span over multiple scales.
The impact of non-swelling clays on Steam-Assisted Gravity Drainage (SAGD) performance was studied in this work. Two SAGD experiments were conducted on a Canadian bitumen by preparing the reservoir rocks with two different non-swelling clays; kaolinite (SAGD1) and kaolinite (90 wt%) and illite (10 wt%) (SAGD2). Change in clay type from kaolinite to a mixture of kaolinite and illite resulted in 15 wt% lower cumulative oil recovery. The role of clays and their interaction with crude oil fractions; namely Saturates, Aromatics, Resins and Asphaltenes (SARA fractions), on process performance was investigated through control experiments under optical and scanning electron microscopy. Pseudo blends of clays and SARA fractions revealed that kaolinite-asphaltenes interaction in SAGD1 occurs at steam condition, however, the same interaction happens for kaolinite-illite mixture at liquid water condition. It has been observed that while kaolinite-asphaltenes interaction is a direct interaction, 10 wt% illite addition to clay (SAGD2) causes an indirect interaction. This indirect interaction occurs due to mainly aromatics-clays association. Clays in SAGD2 were observed to be carried inside asphaltenes clusters. Since aromatics are soluble in asphaltenes, initially a black colored microscopic image was obtained. Upon the evaporation of aromatics, it has been observed that clays still preserve their original white color, however, stuck in asphaltenes clusters. Thus, our results concluded that not only heavy and polar fractions of crude oil, but also non-polar fractions may play an important role in oil displacement during SAGD.
Cai, H. (Research Institute of Petroleum Exploration & Development CNPC) | Zhang, Q. (Research Institute of Petroleum Exploration & Development CNPC) | Yang, S. (Research Institute of Petroleum Exploration & Development CNPC) | Tian, M. (Research Institute of Petroleum Exploration & Development CNPC) | Wang, Q. (Research Institute of Petroleum Exploration & Development CNPC) | Zhou, Z. (Research Institute of Petroleum Exploration & Development CNPC) | Li, J. (Research Institute of Petroleum Exploration & Development CNPC) | Zhaoxia, Liu (Research Institute of Petroleum Exploration & Development CNPC)
Chemical EOR(CEOR) is one of the most effective technologies for the recovery enhancement of mature high water-cut oilfields. Taking Daqing oilfield as an example, great success has been achieved in Alkali-Surfactant-Polymer(ASP) flooding field applications with incremental oil recoveries exceeding 20%. With the depletion of petroleum resources, CEOR methods attract ever-increasing attentions worldwide and expand to reservoirs with harsh conditions, such as high temperature high salinity (HTHS), low permeability, and complicated fault block etc.
CEOR feasibility study was performed for a HTHS complicated fault block with temperature of 78 °C and produced brine salinity at 37570.7 mg/L. Detailed screening and evaluation of CEOR methods including polymer flooding, flowing gel injection, and surfactant imbibition were conducted. Furthermore, core flooding tests were carried out to determine oil displacement performance and optimize injection scheme.
Parallel core flooding test proved that 12.8% incremental oil recovery was obtained by polymer flooding. As to flowing gel injection, a heat tolerant gel formulation was developed with good thermal stability at 78 °C within 30 days. An incremental oil recovery of 14.8% was achieved by flowing gel, 2% higher than that of polymer flooding. Through static imbibition test, an nonionic surfactant with good recovery was selected. Core flooding test resulted in 13.5% incremental recovery by surfactant slug. For combined gel and surfactant imbibition technology, 17.8% incremental oil recovery was achieved in core flooding test.
Pilot test of flowing gel and surfactant imbibition technology was delpoyed in a fault block with 9 injectors and 26 producers. An incremental oil of 2376 MT was achieved after one year injection.
Leunda, G. (Programa de Monitoreo de la Biodiversidad en Camisea) | Dias, G. (Programa de Monitoreo de la Biodiversidad en Camisea) | Mendoza, E. (Pluspetrol Perú Corporation) | Capello, N. (Pluspetrol S.A.)
The research presented herein was accomplished under the framework of the Camisea Project Biodiversity Monitoring Program, with the objective of assessing changes in land use and vegetation cover in Blocks 88 and 56, operated by Pluspetrol Peru Corp. The rate of recovery post intervention was also measured and recorded along a significant period of time (+ 10 years).
The area surveyed comprised approximately 247,000 ha for which satellite images (Landsat, CBERS2 and Aster) were used with mapping scales of 1:100,000 and 1:50,000. For further detail, a second stage using high resolution images (Ikonos, Quickbird, Wordview2 and aerial photography) was also performed.
The results show that after 12 years of continuous operation the total cleared area within both blocks ranges between 0.13 and 0.20 %, with a tendency of remaining steady around the latter. This fluctuation is related with a dynamic of clearing and subsequent restoration works associated with the construction of project facilities, along with natural recovery. The research has provided, as well, data related with recovery rates of cleared areas, which range between 14 and 16 % per year.
Another important outcome of the study shows the relationship between the effect of activities directly associated with the Camisea Project and those conducted by third parties (government infrastructure, other extractive projects and native communities). Measured within a 5 year period, the deforestation rate of the Camisea Project tends to remain steady and has affected a small portion of the area (as previously informed, less than 0.2 %), whereas the surface deprived of vegetation by third parties increased 34 % during the 2011-2016 period.
Above all, the research clearly demonstrates the positive effects of the "
Well deliverability is directly related to the hydraulic fracture conductivity of the created fracture networks. There are several influencing factors on fracture conductivity, including fracture surface topography, mechanical properties, and proppant concentration. Fracture surface topography inherently defines the connectivity of cavities inside the fracture that serve as flow channels, and such flow channels are further enhanced by the presence of proppant. This paper presents a study considering the aforementioned phenomena, centered primarily on the effect of proppant concentration on the primary hydrocarbon-baring Unit B of the Eagle Ford Shale formation.
Laboratory experiments were conducted to investigate the effect of proppant concentration on fracture conductivity for Eagle Ford Shale samples. The test samples were obtained from outcrops at Antonio Creek, Terrell County, Texas. A 100-mesh sand was utilized, as it is representative of the industry practice in the region. Fracture conductivity measurements were conducted by flowing dry nitrogen at varying closure stress stages. Ancillary measurements included Young's Modulus and Poisson's ratio obtained by a tri-axial compression test. The Brinell hardness number was measured by an indentation test, and fracture surface topography was obtained using a laser profilometer.
Results show that the initial evenly distributed proppant concentrations were altered during the process of measuring fracture conductivity, yielding a final proppant distribution that partially occupied the fracture surface. The remaining surface area was absent of proppant and served as channels of high conductivity relative to the areas occupied by proppant. It is believed this behavior occurs in field operations, especially under conditions of varying gas flowrates during production. Additionally, this work suggests the possibility of an optimum initial proppant concentration that can result in the highest channeling behavior for a particular fracture surface.
In this study, the historical production of VacaMuertais evaluated aiming to capture the complexities of this formation in terms of fluids production and recovery performance. This paper integrates the Neuquén province production analysis with the objective to understand the oil and gas historical production behavior in a development area of roughly 12,000 sq mi (31,000 km2).A comprehensive evaluation using public data was conducted to present the contribution and the impact of VacaMuerta oil and gas production on the region and the country.
The VacaMuerta formation represents the most-challenging source of new oil and gas in Argentina, with a huge potential considering the size of the development area in any block across the basin, the reservoir gross thickness and the resulting fluids in place, and the way forward to be achieved regarding the balance between well cost reduction and productivity improvement. There have been important drilling and development efforts in the last 4 years in which both vertical and horizontal wellbore configurations have been implementedand tested over the longterm. However, there are still uncertain factors under evaluation to assess the VacaMuerta formation performance, which achieved 29 million barrels and 124Bcf in December 2016, with 674 oil and gas producer wells.
The workflow focuses on the analysis of historical production for both vertical and horizontal wells, average rates and cumulative production of initial 6 and 12 months, water cut and gas-oil ratio (GOR), decline analysis and vintage performance, with the addition of heterogeneity index plots. Production history statistics and probabilistic analysis were incorporated in the study to summarize and present the evaluation results. Important aspects related to well decline behavior and estimated recovery for the initial years were also analyzed.
In this paper, we present the main findings and results of a complete production analysis of VacaMuerta formation after more than 10 years of production. This paper provides an overview of the historical production performance and the key elements for production forecasting. The integration of this production information with geology, reservoir characterization, well design, and completion and operation strategies provides an essential reference to improve the understanding of the production potential and the visualization and ranking of any well, field, or area in the Neuquén basin.