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.
Harper, Christopher (University of Texas - Dallas) | McBride, Kyle (University of Texas - Dallas) | Ferguson, John (University of Texas - Dallas) | Baldridge, Scott (Los Alamos National Laboratory) | Braile, Larry (Purdue University) | McPhee, Darcy (US Geological Survey) | Keithline, Nathan (College of William and Mary) | Boucher, Chloe (University of California-Santa Cruz) | Mendoza, Kevin (University of California-Merced)
Seismic and gravity data collected by the Summer of Applied Geophysical Experience (SAGE), along with energy-industry seismic data, well data, and geologic maps, go into the construction of geologic cross sections transecting the Rio Grande rift in the area of the Española basin. These cross sections reveal several key structures within the basin including the eastern bounding fault of the Los Alamos graben, and the Agua Fria fault system near the eastern boundary of the basin. Additionally, we find no evidence in the data presented here supporting the linking of the Embudo and Santa Clara faults. Finally, by flattening the geologic cross sections on several unconformity surfaces, a temporal structural progression of the study area is developed. Using the resulting paleo cross sections, we show that the trend of the Laramide Sangre de Cristo uplift likely varied markedly from the modern uplift.
Presentation Date: Wednesday, October 19, 2016
Start Time: 8:25:00 AM
Location: Lobby D/C
Presentation Type: POSTER
The United States National Science Foundation has funded a Sustainability Research Network (SRN) focused on natural gas development in the Rocky Mountain region of the United States. The mission of this SRN is to provide a logical, science- based framework for evaluating the environmental, economic, and social trade-offs between development of natural gas resources and protection of water and air resources and to convey the results of these evaluations to the public in a way that improves the development of policies and regulations governing natural gas and oil development. In a previous paper (
Wellbore construction methods, especially casing and cementing practices for the protection of fresh water aquifers, have been reviewed in these three basins. The wells in the three basins were classified based on coverage of water and hydrocarbon zones as well as age. The assessment confirms that natural gas migration occurs infrequently, but can happen from poorly constructed wellbores. There has been no occurrence of hydraulic fracturing fluid contamination, which was confirmed by our analysis. The significance of these results is to help quantify the risks associated with natural gas development, as related to the contamination of surface aquifers. These results are helping to shape the discussion of the risks of natural gas development and will assist in identifying areas of improved well construction and hydraulic fracturing practices to minimize risk.
In the design of hydraulic fractures, it is necessary to make simplifying assumptions. Fifty years ago, our industry was mathematically obliged to describe fractures as simple, planar structures when attempting to predict fracture geometry and optimize treatments. Although computing tools have improved, as an industry we remain incapable of fully describing the complexity of the fracture, reservoir, and fluid flow regimes. Generally, we make some or all of the following assumptions:
- Simple, planar, bi-wing fractures
- Completely vertical fractures with perfect connection to the wellbore
- Flow capacity that is reasonably described by published conductivity data
- Predictable fracture width providing dependable hydraulic continuity (lateral and vertical continuity)
To forecast production from these fractures, we frequently make the additional assumptions:
- Reservoir is laterally homogeneous
- Modest/no barriers to vertical flow in formation (simplified description of layering compared to reality)
However, we must recognize that all of these assumptions are imperfect. This paper will investigate the evidence suggesting that fractures are often subject to:
- Complicated flow regimes
- Complicated geometry
- Irregular frac faces
- Imperfect proppant distribution
- Imperfect hydraulic continuity
- Imperfect wellbore-to-fracture connection
- Residual gel damage, possibly including complete plugging or fracture occlusion
Additionally, reservoirs are known to contain flow barriers that amplify the need for fractures to provide hydraulic continuity in both vertical and lateral extent.
The paper appendix tabulates the results from more than 200 published field studies in which fracture design was altered to improve production. Frequently the field results cannot be explained with our simplistic assumptions. This paper will list the design changes successfully implemented to accommodate real-world complexities that are not described in simplistic models or conventional rules of thumb. Field examples from a variety of reservoir and completion types [tight gas, modest perm oil, coalbed methane, low rate shallow gas, annular gravel packs] will be provided to demonstrate where the field results differ from expectations, and what adjustments are necessary to history-match the results.
Orocual field is one of the largest growing onshore opportunities in North of Monagas basin, eastern Venezuela. The field is planning to increase its production potential to more than 500% in the next five years. Business plan involve new expansion opportunities with improving field economics. These opportunities include massive development of the shallow heavy oil horizons by steam injection and
development drilling in the deeper light and condensate reservoirs. To accomplish such a challenging goal, it was necessary to estimate new requirements for surface facilities while considering both reservoir uncertainties and multiple development scenarios.
This paper presents a unique and innovated method and a case-study for integrating multiple-reservoir forecasts with a surface facilities network, with economics and uncertainty. Subsurface responses from five Orocual formations were obtained from ten different reservoir simulation models with their associated well constraints. One single surface network model was used to gather production information from all the reservoirs and likewise was used to develop alternate production scenarios. An automated workflow handled the
integration of reservoir production uncertainty, drilling schedule compliance, workover success, economics and varying surface facilities capacities.
The procedure that we have developed in this effort permitted the visualization of a more realistic asset performance compared to requirements in the long-term. The procedure also identified future needs for artificial lift.
The methodology developed also served as a platform for the exhaustive optimization of wellbore and surface equipment sizing in the presence of uncertainties based on front-endloading (FEL) methodology. The procedure allowed the evaluation of parameters that affect uncertainty in well productivity, drilling schedule compliance, workover success, and varying surface facilities capacities, such as project
execution time, workover success, facilities uptime, and facilities spare capacity.
Field production profiles often deviate from simulated ones. Multi-disciplinary field study is traditionally a sequential process; decisions are often broken down and disconnected. Often, reservoir engineers just model reservoir response up to the bottom-hole, production engineers model the whole wellbore up to the well-head, and process engineers model the surface facilities from the wellhead to the tank [Saputelli et al., 2002]. In general, most parties assume constant pressures at the boundaries throughout simulation period.
During field development, not all subsurface uncertainties are considered for evaluating all feasible surface scenarios. Changes in well productivity, water-front advance, free-gas production, and fluid composition will affect both reservoir and surface response. Because of the previous, surface facilities may remain sub-utilized, reservoir potential may not be obtained, and field economics may not be achieved at peak performance.
PDVSA has implemented a planning methodology for selecting the optimal field exploitation strategy called MIAS (sustainable integrated asset modeling) [Acosta et al., 2005; Khan et al., 2006]. MIAS Orocual project's objective is to assure optimal short-term field operating strategies in agreement with long-term reservoir management objectives with social and environmental responsibility. Before the
project began, MIAS Orocual project required the readiness of a platform [Rodriguez et al., 2006] for the quantification of subsurface, wells, and surface uncertainty variables and the evaluation of the effect on the value creation.
An automated workflow for integrating multiple numerical reservoir simulated production profiles within one surface facilities network was developed and is presented in this paper.
Le Maux, Thierry (Beicip-Franlab) | Mattioni, Luca (Beicip-Franlab) | Rouvroy, Patrick (Beicip-Franlab) | Guaiquirian, Luis (Petroleos de Venezuela S.A.) | Gonzalez, Pedro (Petroleos de Venezuela S.A.) | Gonzalez, Angel (PDVSA) | Hernandez, Maria Manuela (Petroleos de Venezuela S.A.)
Orocual field is an anticline located in the East of Venezuela within El Furrial Trend. The San Juan Formation, a tight Late Cretaceous-Early Paleocene sandstone, is one of the best producing reservoir of Orocual. Located at a depth of about 14000 feet, it is characterised by a low matrix porosity (5 to 6%) and permeability (below 5 mD in average). Very quickly identified as a possible fractured reservoir due to the difference between producers' performance and petrophysical data, this hypothesis was later confirmed with the acquisition of cores and borehole image logs ‘BHI'. Both show the presence of numerous open or partially open tectonic fractures.
The present paper focuses on one of the four structurally compartmentalized fault blocks of the field that presents the highest potential of reserves. It is shown how all available data, geology (Bore Hole Image logs, cores and wireline logs), geophysics, and reservoir engineering data (production data, flowmeters, welltests) were combined to identify the main types of fractures, to predict their occurrence in the reservoir and to determine the hydraulic properties of the different fractures sets. The DFN approach was used to characterise the natural fractures at well scale and to model the full field 3D fracture network. From BHI and core analysis, it was found that the formation Vshale and the porosity were the main geological drivers on natural joints (small scale fractures) occurrence. Those properties associated to the matrix were used to populate in 3D the fracture network model. A second type of fractures, large scale fractures associated to faults, although not identified on wells but strongly suspected to exist, have also been included in the 3D model. The model was hydraulically calibrated first through simulation of a measured flowmeter log with the DFN model and then through match of the KH measured from transient welltests with the KH derived from the model.
The outcome of the study is a reliable set of fracture properties that can directly be used in the 3D simulation model in order to improve the current history match and evaluate injection scenarios for the future.
The Orocual field is located in the Maturin sub-Basin within El Furrial Trend. It produces from 3 different reservoirs: the Plio-Pleistocene Mesa and Las Piedras Formations, the Miocene Carapita Formation and the Late Cretaceous-Early Paleocene San Juan Formation. This last reservoir, the one of interest here, lies between 12500 and 16000 ft deep. Formed as a succession of clean and shally sandstone intervals, it is classically sub-divided into 3 units: the Upper San Juan, the Middle San Juan (the best unit) and the Lower San Juan. The quality is poor, even in the cleanest interval, with an average porosity of 5% and permeability below 5mD in average.
The field is sub-divided in 4 different fault blocks which are likely to be isolated. The present study focused on one of those fault blocks called San Juan 6 (top map in Figure 1). The Oil API varies between 25° and 41°, the lighter being close to the top.
As often, the presence of natural open fractures was first detected while drilling with the occurrence of unexpected mud losses. The higher wells productivity than first expected from matrix characteristics also indicated the likely presence of producing fractures. The presence of a natural fracture network was then confirmed through core description and Bore-Hole Image logs acquisition and analysis.
Integrated 3-D and 2-D gravity modeling, 2D seismic profiling and geology of salt anticlines in the Paradox Basin, Colorado and Utah have a benefit over Gulf Coast salt studies in that they involve large vertical relief salt ridges that displace high density Paleozoic-age overburden. Density contrasts between the salt and overlying Pennsylvanian and Permian age clastics and minor carbonates are larger than seen in the Gulf Coast Mesozoic and Cenozoic rocks. New interactive 3-D gravity modeling can be performed very quickly and effectively by integrating seismic and well data in multiple windows interactively. Gas exploration is expanding in the Paradox Basin in response to higher gas prices and access to pipelines with ready markets. Wells historically drilled in the northern part of the basin were considered uneconomical unless they found oil. Structural leads mapped by 3-D gravity modeling in the Paradox Valley are likely to find good trapping mechanisms for gas charged reservoirs that have been shut in previously.
A field trial was initiated to investigate the effect of additional fracture conductivity upon production from the low-permeability sandstone of the Pinedale Anticline in western Wyoming. Forty million pounds of proppant were pumped into 221 stages within 14 new wells. Seventeen production logs were performed during the three-year trial to determine the productivity of fractures propped with sand, resin-coated sand, or ceramic proppants.
The trial was specifically designed to maintain identical stimulation strategy with the exception of proppant type used in each stage. Proppant selection by stage was adjusted to provide reliable offset comparisons.
In addition to comparing individual stage production, total well rates and estimated ultimate recovery (EUR) all indicate that production rates from fractures receiving upgraded proppant are significantly higher than production from similar stages in offset wells.
Detailed analyses have been conducted to normalize data for reservoir quality, pay, pressure, and drawdown. Regardless of whether raw production data or normalized results are considered, upgraded stages are found to provide 180% to 400% of the gas rate from identical stages receiving lower conductivity proppant.
Four trial wells which received upgraded proppant in 35% of the stages provided 44% higher peak rates from the composite well, and sustained higher rates after reaching 250 and 500 MMCF cumulative production milestones. Based on current production profiles, these four trial wells are expected to recover significantly higher EUR than offset wells completed by this or other operators.
Where possible, productivity of these wells will be compared to 47 additional wells in the area completed by other operators. Although the results achieved by other operators have not been normalized for reservoir thickness or permeability, production from the four trial wells receiving the highest proportion of ceramic proppant provided 155 to 214% the peak rates and 158 to 178% the EUR of wells completed by other operators in this area.
Results from this trial demonstrate benefits from improved fracture conductivity far beyond what is predicted by current production models, even after incorporation of non-Darcy, multiphase flow, and cyclic stress impacts. At a gas price of $4.50/mscf, the productivity of a stage only needs to be increased by ~5% to repay the full cost of upgrading proppant with the first year's incremental production. The incremental cost to upgrade a typical frac stage (175,000 lbs.) of resincoated sand (RCS) to Economy Light Weight Ceramic (ELWC) was $17,500. The large production improvements observed in this study far exceeded economic hurdles, repaying the incremental investment within 20 days and generating $300,000 incremental cash flow in the first year for each upgraded stage.
Results indicate that treatments are not yet optimized, and further increases in fracture conductivity are merited. Based on these encouraging results, a well completed seven miles northwest of this trial area received ceramic proppant in all 19 stages, with no use of sand or resin coated proppants. This new "Gannett" well had only one offset, and therefore did not provide ideal well control. Nonetheless, this location was selected because it was on private land and not subject to the seasonal drilling closures stipulated by the BLM in the central Mesa area. This new well was drilled to a greater total depth, and presented more total pay than the single offset. However, based on the first 70 days of production, rates are inferior to the parent well and have not substantiated the large increase in production observed in the trial area. It was noted that the frac gradient exceeded 1.0 psi/ft in all stages in the new Gannett well. Additionally, this new well is producing 200-300 barrels of water per day, while the parent well treated at lower pressures, and produced a more typical 30-40 bwpd. Although the recent Gannett well has failed to replicate the success seen in this trial, two additional wells in the Mesa area have been designed to receive ceramic proppant in every stage.
Dorta, G. (PDVSA Intevep) | Boujana, M. (EGAL Geological and IT Services Company) | Zerpa, L. (PDVSA Intevep) | Ramonez, M. (PDVSA Intevep) | Velasquez, C. (PDVSA Intevep) | Castillo, E. (PDVSA Intevep)
For the first time, in Venezuela, a detailed, complete study of naturally fractured reservoirs using the recent technological advances was performed. Since the first drilled well within the very tight (5 mD) cretaceous sandstone (San Juan Formation) diagenetically highly cemented by quartz overgrowth, the existence of natural fractures was suspected due to high production rates (3000 bopd) after hydraulic fracturing an interest in fractures characterization became important for the field. Furthermore, these assumptions were growing with the analysis of pressure transient tests of several DST and Build-up surveys, which have shown double-porosity behaviour. During the drilling it was frequently observed strong lost of circulation at several depths within the San Juan Formation.
Orocual Field, within El Furrial Trend, located in North Monagas area, East of Venezuela, is structurally a Fold Propagation Fault resulting in anticlines associated with thrust faults. San Juan Formation, a complex barrier island deposits, bearing condensated fluids (41° API) is the most important reservoir within Orocual Field.
Cores and Well Logs provided the basis to strongly confirm the presence of a fracture network within the reservoir. With the use of recent technological advances (core scanning and imaging, side-by-side display) which permits a detailed core-log calibration and integration, a NNW-SSE orientation of the fractures observed and measured in the cores was possible, the findings are consistent with the regional tectonical stress. Integrated analysis with breakouts borehole image processing, 3D seismic structural interpretation, in-situ stress measurements and second derivatives maps yield us to establish the first maps of fractures orientation and density.
Parameters such as aperture, spacing, density, length and angles have been measured to define patterns and tendencies that it will feed the simulated dynamic fractures model.
A better understanding of the historical production behaviour has been reached and a simulated, geostatistical fractures modelling is under development to establish correlative trends matching between production and fractures network orientation, density and dynamical properties of the fractured system.
Orocual field is located within the El Furrial Trend, one of the best producing fields in East Venezuela, trapped between the deformation front thrust to the south and the Pirital thrust to the north (Fig. 1). It is situated in a regionally compressive regime. Structurally, it is a northeast-southwest anticline, thrusted to the southeast. Three diferent geological ages reservoirs are producing within this field: The Plio-Pleistocene Mesa and Las Piedras formations, the Miocene Carapita Formation and the Late Cretaceous-Early Paleocene San Juan Formation. This last formation has been subdivided into three members (Lower San Juan, Middle San Juan and Upper San Juan).
The San Juan Formation reservoir, containing 291 MMBls, was discovered in 1985 with the drilling of well ORS-A at depth 14119 feet, and produced Gas Condensate of 41° API (1050 bppd; 4762 cf/bl; 0,5% BS&W) with an initial measured pressure of 7470 psi at 13000' subsea. Further drilling development have shown the existence of a 34° API crude oil within the deepest flanks of the anticline structure, suggesting a compositional differential column. The average permeability is between 5 to 10 mD and porosity average is around 6%. These low petrophysical parameters values can be explained by the high cementation (quartz overgrowth) observed with the microscopy in thin sections.
This paper summarizes an integrated field, experiments and computer simulation research program conducted to support a review of the reserves and development plan for the Hamaca Area in the Orinoco Belt (OB), Venezuela. The impact of the foamy oil mechanism on the Hamaca heavy-extra heavy Oil reserves and the importance of understanding this behavior is presented in this paper. The study was conducted in reservoirs with the largest production history (within the OB). The experimental results showed in-situ formation of non-aqueous oil foam with high gas retention, improving oil mobility and leading, therefore, to high well productivity. An experimental recovery factor over 10% was obtained under primary conditions so it was possible to increase oil reserves by approximately 30% over the currently accepted volumes. Experimental results provided input parameters to perform preliminary simulation runs which would allow the modification of well spacing schemes, the generation of a high-probability production profile, and the optimization of artificial lift systems, incorporating larger capacity equipment.
When the exploitation of Hamaca heavy oil reservoirs began, it was assumed that the primary production mechanisms were sand compaction, solution gas drive and thermal effects due to steam cyclic stimulation which improves oil mobility. However, an unexpectedly high cold production lead to research of the drive mechanisms to explain the special production performance. Similar behavior has been observed in the Lloydminster area of Canada. Despite considerable speculation, a number of authors have studied foamy oil behavior and some research has recently been done, yet the mechanism leading to this behavior still remains to be successfully explained. Reservoir properties that were proposed to explain the behavior in the OB and in Canada include unusually high sand permeability and/or critical gas saturation. In Canada, high critical gas saturation is now an accepted property of some reservoirs, the so called Foamy Oil reservoirs. However, a monitoring field program of sand compaction and land subsidence did not show any evidence that this mechanism has taken place in the Hamaca Area. None of these proposed properties and mechanisms are consistent with field observations. On the other hand, numerical models showed high uncertainty when trying to match the reservoir production pressure behavior. As a consequence, a research program was designed as part of an integrated reservoir study. It included a production behavior analysis, an experimental program for fluid/porous media characterization through conventional and nonconventional PVT tests, and solution gas drive experiments at research centers of Venezuela (INTEVEP), Canada (PRI-CMG) and USA (LAB).