Heavy oil is defined as liquid petroleum of less than 20 API gravity or more than 200 cp viscosity at reservoir conditions. No explicit differentiation is made between heavy oil and oil sands (tar sands), although the criteria of less than 12 API gravity and greater than 10,000 cp are sometimes used to define oil sands. Unconsolidated sandstones (UCSS) are sandstones (or sands) that possess no true tensile strength arising from grain-to-grain mineral cementation.
The claim that the world is irresponsible in rapidly consuming irreplaceable resources ignores technical progress, market pressures, and the historical record. For example, the "Club of Rome," with the use of exponential growth assumptions and extrapolations under static technology, predicted serious commodity shortages before 2000, including massive oil shortages and famine. First, the new production technologies are proof that science and knowledge continue to advance and that further advances are anticipated. Second, oil prices will not skyrocket because technologies such as manufacturing synthetic oil from coal are waiting in the wings. Third, the new technologies have been forced to become efficient and profitable, even with unfavorable refining penalties. Fourth, exploration costs for new conventional oil production capacity will continue to rise in all mature basins, whereas technologies such as CHOPS can lower production costs in such basins. Fifth, technological feedback from heavy-oil production is improving conventional oil recovery. Finally, the heavy-oil resource in UCSS is vast. Although it is obvious that the amount of conventional (light) oil is limited, the impact of this limitation, while relevant in the short term (2000 to 2030), is likely to be inconsequential to the energy industry in the long term (50 to 200 years). The first discoveries in the Canadian heavy-oil belt were made in the Lloydminster area in the late 1920s. Typically, 10- to 12-mm diameter perforations were used, and pump jacks were limited by slow rod-fall velocity in the viscous oil to a maximum of 8 to 10 m3/d of production, usually less. Operators had to cope with small amounts of sand, approximately 1% in more viscous oils. Small local operators learned empirically that wells that continued to produce sand tended to be better producers, and efforts to exclude sand with screens usually led to total loss of production. Operators spread the waste sand on local gravel roads and, in some areas, the roadbeds are now up to 1.5 m higher because of repeated sand spreading. The sharp oil price increases in the 1970s and 1980s led to great interest in heavy-oil-belt resources (approximately 10 109m3). Many international companies arrived and introduced the latest screen and gravel-pack technology but, in all cases, greatly impaired productivity or total failure to bring the well on production was the result. To this day, there are hundreds of inactive wells with expensive screens and gravel packs. The advent of progressing cavity (PC) pumps in the 1980s changed the nonthermal heavy-oil industry in Canada. The first PC pumps had low lifespans and were not particularly cost-effective, but better quality control and continued advances led to longer life and fewer problems. The rate limits of beam pumps were no longer a barrier and, between 1990 and 1995, operators changed their view of well management.
Rodriguez, Inti (Petrolera RN LTD.) | Hernandez, Edgar (Petrolera RN LTD.) | Velasquez, Richard (Petrolera RN LTD.) | Fernandez, Johanna (Petrolera RN LTD.) | Yegres, Frandith (Petromonagas) | Martínez, Rosana (Petromonagas) | Contreras, Ronald (Petrolera RN LTD.) | Korabelnikov, Alexander (Petrolera RN LTD.)
The Morichal reservoir at the Cerro Negro Extra Heavy Oil Field (Petromonagas JV) is starting its mature development phase after more than 18 years of production. In order to improve the current recovery factor which is around a value of 3%, maintain the production and reduce operational costs, two different strategies were defined: First, the use of the Jobo Member (overlaying sand deposits) to dispose the wastewater produced from the Morichal reservoir and second, the use of the shallow aquifer deposits of Las Piedras Formation as a water source for future massive implementation of EOR projects (Polymer and steam flooding), evaluating the potential origin of this water based on its physical and chemical properties. Both geological units are part of the drilled stratigraphic column of The Cerro Negro field, what brings technical and economical advantages such as high density of geological information available and the reuse of abandoned wells. This paper aims to describe the study case of the Cerro Negro Oil Field where on one hand, a static and dynamic characterization of Jobo Member was carried out in order to define the potential areas to be used as a wastewater disposal of the Morichal Member production. Based on the geological characterization, dynamic evaluation and surface facilities analysis, it was selected as the best area to dispose of more than 35,000 B/D of water derived from the production of 330 horizontal wells drilled; as well as, support the strategy of producing wells with high water cuts in zones of perched water and close to water contacts, where an important volume of oil is located which until now has been bypassed. On the other hand, the aquifer characterization of Las Piedras has allowed us to define the volume and composition of water available to use as a secure and probed water source during the EOR project implementation.
Summary A workflow to generate seismic well ties in PS converted wave seismic sections using sonic logs was created by estimating Vp/Vs relationships and the time difference between the arrival time of the P-P and the PS waves to several key events. The results were PS converted wave synthetic seismograms tied to well-defined seismic reflectors at different depths. These positive results made possible the creation of a step by step workflow to tie wells to converted wave seismic and generate synthetic seismograms. Introduction The seismic method of reflection P-P wave has been the most important exploration method in the oil and gas industry. Nevertheless, this method does not clarify all the uncertainties that can be encountered during subsurface exploration and development.
Bao, Yu (Research Institute of Petroleum Exploration & Development, CNPC) | He, Liangchen (Liaohe Oilfield Company Ltd, Petrochina) | Lv, Xue (Sino-Pipeline International Company Ltd.) | Shen, Yang (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Xingmin (Research Institute of Petroleum Exploration & Development, CNPC) | Liu, Zhangcong (Research Institute of Petroleum Exploration & Development, CNPC) | Yang, Zhaopeng (Research Institute of Petroleum Exploration & Development, CNPC)
The Orinoco heavy oil belt in Venezuela is one of the largest extra-heavy oil resources in the world. It has become a major goal for the unconventional oil exploitation in these years. Now, the most common production method is to use the horizontal well cold production without sand. It is an economic and commercial process, and with the reservoir of this area have high initial gas to oil ratio (GOR), porosity and permeability with unconsolidated sand. However, after several years' production, the oil rate draws down quickly caused by the reservoir pressure drops; the key challenge of cold production is that the recovery factor (RF) tends to be only between 8% and 12%, implying that the majority of the oil remains in the oil formation. It is necessary to develop viable recovery processes as a follow-up process for cold production. Generally, steam based recovery method was widely used as a follow-up process for cold production. In this paper, steam fracturing (dilation) Cyclic Steam Stimulation (CSS) operation and Non steam fracturing (No dilation) CSS operation by using reservoir simulator is examined for a post cold production in extra heavy oil reservoir, in order to analyze the performance of the oil rate, cumulative steam-to-oil ratio (cSOR), steam depletion zone, greenhouse gas emission and some necessary parameters.
The key component of the steam fracturing (dilation) is the ability to inject high temperature and pressure steam into the formation to fracture the reservoir rock which in turn raises the rock permeability and mobilized the oil by lowering the visocisity. To compare the results of the dilation and no dilation CSS operation, this study reveal that due to the steam is injected into the reservoir by using the same cumulative cold water equivalent (CWE), the steam condensate; pressurized by steam vapour, fracture the formation. Dilation operation achieves higher oil rate, lower cSOR. The result also show that fraturing (dilation) of the reservoir during steam injection relieves the pressure which in turn lowers the steam injection pressure below the case where No dilation operation ouccurs.
Design a completion system for sand control based on top technology as an alternative to the slotted-liner completions systems currently installed in extra heavy oil producing wells in unconsolidated formations.
The methodology and design are based on the resulting interpretations of Dry Sieve Analysis (DSA), Laser Particle Sieve Analysis (LPSA), and geological considerations. Based on the results of these analyses, uniformity coefficients were calculated and grain size sorting results were used to validate the completion criteria, the system type, and the open area to be used. Once these criterions were selected, the Sand Retention Test (SRT) was utilized in the laboratory to verify the performance of the design using different liner sections and core plugs specific to the area; which allowed the selection of the appropriate system. Quantifying the total recovered barrels with the new completion system was done using a nodal analysis in order to evaluate the cost benefit in a typical well.
As result of the interpretations of the tests, it was determined that the open area size of the completion system should be 200 μm, being estimated by the D10 obtained by the DSA realized to the core "A" of the Lower Morichal Formation. With the LPSA realized to the core "B", the quantity of thin grain movables less than 45 μm was estimated for the Lower Morichal Formation. All of these criteria were unified to select the completion method best suited for sand control. The results shows that the best option is metal mesh screen, which offer 150% more flow area in comparison with the slotted liner which translates to a recovery of 10% in production according to nodal analysis simulations.
While current design practices sometimes take into consideration grain size distribution and sorting, this paper highlights the added benefit of combining this approach with the laboratory results of the DSA and LPSA testing methods to ensure that production recovery is truly maximized.
In some of the giant extra-heavy oil fields from the Orinoco Oil Belt (OOB), the challenge is to increase recovery over primary production by about 10%, to meet its ambitious development plan. To get this, it is necessary to apply EOR processes.
It is visualized the integral design of a cyclic steam stimulation (CSS) pilot test, using a high steam injection rate. It is identified and quantified the main variables and operational parameters affecting the performance of CSS, for an oil field at OOB.
The design of this pilot test covers the location of the area, visualization of thermal well, identification and quantification of the variables that potentially influence to a greater extent the performance of this technology, conceptual design of EOR surface facilities and a complete monitoring plan.
A cluster with 10 long horizontal wells of different lengths is evaluated. The variables studied are: specific steam flowrate per unit length of well, well length, and well thermal insulation. We apply design of experiments to select the combinations of the values taken for the different variables. The duration of the different stages in every cycle is given by previous results applying optimization of CSS to sector modeling.
The main constrains dictated for the thermal well are identified and taken into account to define the maximum steam injection and production rates for this test.
The pilot test is simulated for three complete cycles, with two approaches: High (2.2 – 3 bbl/day*ft) and Low (1.5 bbl/day*ft) specific steam flowrates. Important production variables as drawdown, bottom-hole pressure, field average pressure, gas oil ratio and water cut have been evaluated.
Results for the main operating parameters (High/Low approaches), and the economic evaluation, are shown. These results show once again that higher specific steam flow rates get higher recovery and are even more profitable.
The study encourages a review of the paradigm that limits steam injection rates in high-productivity projects currently underway at OOB. Additionally, it is identified that at present is the thermal well and not the surface facilities, which limit the application of CSS at higher rates, needing an urgent improvement in its concept.
The steam injection rate is conventionally expressed as daily rates (bbl/day), absolute amounts per unit thickness of formation (bbl/ft), etc. This practice creates misunderstandings, especially in the case of horizontal wells. The variable proposed in this study (specific steam flow rate per unit length of well) is valid for any type of well, and it has a physical significance related to well injectivity.
Another novelty introduced in this study is a higher specific steam flow rate (2.2-3 bbl/day*ft), between 50% and 100% higher than references found in the literature (1.5-2 bbl/day*ft).
In this study we performed a seismic interpretation from reflected PP and PS converted wave data acquired over 95 Km2 in the Orinoco oil belt, Venezuela. The goal of this study was to incorporate the PS wave information to improve a heavy oil reservoir characterization and to enhance the reservoir delineation in a complex stratigraphic setting. In order to achieve the scope several sources of information were analyzed and integrated. Compressional and shear wave slowness logs where used to estimate the PS time-depth function after scaling the PP time-depth functions available in the location covered by the seismic survey. The PS time-depth functions obtained were used to transform well logs and tops from depth to PS reflection time. We generated PP synthetic seismogram in PS time domain to calibrate the PS seismic volume and proceed to interpret the PS seismic volume.
After calibration of the PP and PS seismic volumes two horizons were interpreted along the reflections associated with the target reservoir. These horizons were used to estimate seismic attributes in both PP and PS seismic volumes. We found that the attribute amplitude weighted by instantaneous frequency of the PS-wave correlated better with sand thickness than the same attribute estimated from PP-wave. This can be partly attributed to the differences in resolution between PP and PS-wave. We conclude that the low resolution of the PS-wave make it more sensitive to thickness variation of the sand bodies at the target level due to the tuning effect.
Presentation Date: Tuesday, September 26, 2017
Start Time: 1:50 PM
Presentation Type: ORAL
Rodriguez, Ricardo (PDVSA) | Villavivencio, Elvio (PDVSA) | Bellorin, Pavel (PDVSA) | Rendon, Lerrys (PDVSA) | Orozco, Jose (Schlumberger) | Quintero, Andreina (Schlumberger) | Chapellin, Alvaro (Schlumberger) | Mutina, Albina (Schlumberger) | Bammi, Sachin (Schlumberger)
The Orinoco Oil Belt (Faja) is the largest known heavy oil reserve in the planet. Geologically, its reservoirs are composed mainly of sequences of shales and unconsolidated sands. The properties of the sand units such as shale volume, water saturation, porosity, and thickness can present lateral heterogeneity at a few hundred feet scale. The high viscosity of the oil and its variation both laterally and vertically is one of the key features of the Faja. Prediction of water saturation from resistivity can be difficult due to multiple reasons, including the low salinity of the formation water and wettability changes.
For the field development, Faja reservoirs are drilled following a specific drilling pattern called a “macolla”. A macolla is composed of a vertical stratigraphic well followed by a group of two to four highly deviated wells (slant wells). These deviated wells play a fundamental role in cluster delineation, because they are key calibration points in the trajectory planning of the subsequent set of horizontal wells, which are completed with a slotted liner to maximize production.
Usually, in Faja, only vertical stratigraphic wells include comprehensive logging suites. These suites include elemental gamma ray spectroscopy, microresistivity images, sonic, dielectric, and magnetic resonance measurements at multiple depths of investigation. Moreover, due to the complexity of logging highly deviated wells in unconsolidated formations, many slant wells are not logged or logged only for correlation (gamma ray and resistivity logs). The ability to acquire more log data in the slant wells improves reservoir description and reduces the uncertainty in the planning of horizontal production wells.
The case study presented here illustrates the value of integrating data from vertical and slant wells in a macolla cluster. Comprehensive logging suites acquired in the vertical wells are complemented with through-the-bit logging suites acquired in the slant wells. Through-the-bit technology has recently been introduced in Venezuela and has proved to enable the acquisition of high quality logs through unconsolidated sand shale sequences in highly deviated boreholes. Rig time due to the logging operation and the risk of sticking of the logging string was also reduced.
This case study presents the workflow for and the results of the multiwell data integration in which different formation properties, including lithology-based facies, are propagated and incorporated into a 3D structural model. This workflow provides critical input to reservoir characterization and facilitates significantly the planning of horizontal wells.
Huyapari is a giant field, located in the Orinoco Heavy Oil Belt of eastern Venezuela. Huyapari contains huge original oil in place (OOIP) of extra heavy crude oil (7 to 9°API) with excellent reservoir properties that enable primary production of the extra heavy crude oil by using long horizontal wells. Nevertheless, the live oil viscosity variation at reservoir conditions (1,500 to 20,000 cp) represents a production challenge in the field. This study aims to improve the fluid heterogeneity understanding in the field through the application of PVT (Pressure, Volume and Temperature) and geochemical analysis for oil viscosity estimation.
Fluid heterogeneity mapping using crude fingerprint analyses was performed to understand the variability of the oil biodegradation level across the field. PVT data provided reservoir GOR and supported the oil chemical variation. Biomarkers correlations were also evaluated to obtain a better estimation of oil viscosity, and then compared with oil viscosity measurements performed at surface and reservoir conditions.
The integration of geochemical analysis with the PVT data allowed to improve the Huyapari field correlations used for well potential estimation. A shallow reservoir of the field with few production wells and larger prospective areas was chosen to evaluate its oil viscosity variation and the methodology application. A better well placement and reservoir management strategy was established, thus demonstrating the value of this data integration.
This study demonstrates that reservoir geochemistry coupled with reservoir engineering data is a cost-effective reservoir management tool. This methodology could be useful for application in other extra-heavy oil fields where little reservoir geochemistry input has been considered in their field simulation procedures.