Viscosity is one of the gas properties that is always uncertain at high-pressure and high-temperature (HPHT) conditions because no reliable correlation has been developed for HPHT and accurate measurement of gas viscosities at HPHT is difficult. However, the industry currently does not pay sufficient attention to the need for accurate gas viscosity values in HPHT gas fields' development.
We show that small errors in gas viscosity affect the inflow performance relationship (IPR) curves and eventually change the reserves estimate for HPHT conditions in ways that can drastically influence production forecasting. A sensitivity analysis for a synthetic case at these conditions shows that a 1% error in gas viscosity measurement results in a 1% error in gas flowrate, which in a large scale of gas production may severely underestimate or overestimate recovery from an HPHT field. This linearity between gas viscosity and gas flowrate continues to ±10% errors.
An evaluation of gas viscosity correlations commonly used in the industry shows that none of them is reliable at HPHT conditions, mainly for two reasons: measured data are not available to confirm their consistency and they do not account for impurities in the gas.
Clearly, the industry needs accurate gas viscosity measurements and needs a new procedure to develop correlations based upon accurate HPHT gas viscosity data.
Oil viscosities of about 2 cP and above (under downhole conditions) are common and often exhibit poor end-point mobility ratios when displaced by water in fields under waterflood or with active aquifers.This causes a triple hit on the recovery factor:
This is made worse by reservoir heterogeneity.
The commonly used concepts of productivity index (PI) and injectivity index (II) are not particularly useful when the mobility ratio is high since they require the use of a nominal drainage radius, whereas a two-fluid system with a moving fluid is more appropriate.
The novel concept of the injectivity productivity index (IPI) has been developed to consider a pair of wells comprising an injector and producer, and replaces the use of II and PI. The IPI method helps to quantify waterflood issues in the presence of poor mobility.
This paper will cover three main areas:
Stuck pipe incidents and excessive torque and drag have been common problems encountered while drilling horizontal wells in the Orinoco Oil Belt which contains Venezuela's largest heavy oil reserves concentration. These incidents have been attributed mainly to high levels of friction between the drillstring and the heavy oil sands. To help prevent sticking, a common practice has been to add 10 to 20 vol% of diesel to the water-based fluid when drilling the horizontal sections. Open hole displacement of mud by diesel had also has been used to free stuck pipe. However, many of these incidents have resulted in the loss of the bottomhole assembly and the need to perform sidetrack operations.
Typically, engineered fluid solutions have been required to solve friction issues related to horizontal sections and tortuous well geometries. Additionally, a hydrocarbon-free and non-damaging lubricant option has been necessary to help prevent excessive torque and drag when drilling 2D and 3D well trajectories with a water-based fluid.
Recently, a viscoelastic drilling fluid comprised of a blend of special synthetic oils and surfactants has helped reduce the coefficient of friction in water-based mud by as much as 50% without adversely affecting the rheological properties, as well as dissolving bitumen and preventing emulsification of the heavy oil and sand. After the lubricant treatment, torque and drag values experienced while drilling highly deviated sections through unconsolidated sands at instantaneous penetration rates of up to 1,300 ft/hr have decreased from 18,000 to 12,000 lbf-ft. Also, because no stuck pipe incidents occurred and clean-up trips weren't required, considerable rig time was saved.
This paper discusses key aspects of the performance of the water-based, hydrocarbon-free, non-damaging lubricant used in drilling the Orinoco Oil Belt horizontal and multilateral wells, as well as the factors that enabled PDVSA to achieve project targets in a safe and timely manner and to minimize any detrimental environmental impact .
Prolonged depletion in mature fields renders oil and gas companies to tap more difficult reserves to access and produce. New directional LWD measurements are providing valuable technical support to geoscientists helping them to precisely locate and delineate layer boundaries and fluid contacts in real time. Furthermore, by means of LWD measurements, well trajectory is enhanced which is helping field operators to reduce capital spending by decreasing the probability of facing wellbore stability problems.
Horizontal well placement and trajectory is a critical issue when developing reservoirs based on this technology. Furthermore, reservoir depletion and well performance will be directly linked to well's construction's features. In order to attain these goals, real time azimuthal measurements are essential in helping to properly design, construct and terminate deviated wellbores in a prolific pay section.
PDVSA E&P has successfully applied such technology in reservoirs of 15'-20' sand thickness achieving reduced risks in well placement and obtaining increased productivity indexes increasing oil output by 22%. Detailed description of field cases are shown along with tool's characteristics, benefits and drawbacks are illustrated with field data.
Heavy oils are an important energetic resource because they represent a significant part of the world reserves. The countries with the largest quantity of these resources are: Canada and Venezuela. Several studies have been done on heavy oils and they express the influence of the temperature, viscosity and density on velocities and the frequency content of the signal propagating through the reservoir (Batzle and Hofmann, 2006; Behura et al., 2007; Han and Liu, 2007). These investigations have shown that the relationships developed for conventional oils cannot be applied for heavy oils.
The aim of this research was the evaluation of feasibility of elastic parameters estimation in heavy oil using prestack seismic inversion. In particular, the estimation and quantification of S impedance and density, which are essential properties to describe heavy oil. The results of this study show that the estimation of elastic parameters is possible under certain conditions. In fact, beginning with the design of the seismic survey up to the processing sequence must be taking into account.
The significance of this study relies on the evaluation of a geophysical methodology which allows the integration of different kinds of data, not only to reduce the uncertainties but to get a better imaging of the reservoir under study. In the same way, this technique allows to optimize the well location and a better understanding of the reservoir.
This pdf file does not include the figures. A version with figures is not available.
In the Neuquen basin, center west of Argentina, a tight gas field was developed in submarine volcanic rocks. The field called Cupen Mahuida is a faulted anticline, which produced oil and gas from the upper formations. This deeper reservoir was discovered in 2001. The average depth is 3500 m and there are 16 wells producing from these rocks. The production is dry gas with a low CO2 content.
Because the low permeability hydraulic fractures are needed to produce the wells and the productivity of them is highly variable. The pressure behavior during the fracture pumping showed the presence of natural fractures.
These highly variable results in the wells pushed to get a more predictable reservoir model, and then 99 m of cores, 58 sidewall cores and 8500 m of cuttings were described in detail. Based on the information obtained the geological model was adjusted. Was found that these rocks were originated in volcanic eruptions both sub aereal and submarine and the eruptive products were deposited in a water body. There were several volcanoes feeding the area and were located about 20 km away from the deposits, and then the deposits have a distal position from the volcanoes. A probable volcanic center in the NE of the field was identified. Only one event has had sub areal exposition and could be use as a local correlation level.
Micro fractures due to cooling, gas escapes, etc that are common in this kind of rocks when they are deposited sub aerealy are not present. The primary porosity was completely occluded and the current porosity is due to mineral dissolution. Open natural fractures are present but the density is low as well as the fracture width, some tectonic micro fractures were identified.
The detailed rock analysis allowed to define the depositional environment, this knowledge changed the approach to analyze the porosity distribution.
There are micro fractures, although this is not the largest source of porosity, primary porosity was destroyed because the rock alteration, the main porosity source came from the mineral dissolution.
Oliveira, Michel Fernandes (U. Federal Rio Grande do Norte) | Barillas, Jennys Lourdes Meneses (U. Federal Rio Grande do Norte) | da Mata, Wilson (U. Federal Rio Grande do Norte) | Dutra, Tarcilio Viana
There is still a large amount of natural resources in heavy oil reservoirs which can be explored using new methods. However, this enormous amount of hydrocarbon resources which are in these reservoirs may be explored with new concepts. The VAPEX process is a promising recovery method. The process consists in two horizontal wells, parallel between themselves, producer and injector, where vaporized solvent is injected with the objective of reducing the oil or bitumen viscosity. The purpose of this work is to examine how some important operational and reservoir parameters influence the VAPEX process, in the produced oil rates, in the cumulative produced oil and in the recovery factor. Parameters such as the spacing between wells, the injection pressure, and type of solvent, oil viscosity, residual water saturation and horizontal permeability are addressed in this study. The choice of solvent to be used in the process was the factor that most significantly influenced the process, allowing a greatest recovery factor of oil. The largest cumulative oil recovered was obtained for other parameters of significant influence as the longest distance between wells, increased horizontal permeability and lower injection pressure.
We have already more than X hundreds wells!! ....... We do not need a seismic cube now, do we?????
Who has not heard that kind of exclamation/question while working in oil/gas field development??
Casabe oil field was not the exception. Discovered in 1941, it's been in production since 1945. It cumulated 297 MM bbl of oil (October 2008) with more than 1100 wells drilled.
Since 2004, it's been operated by an Alliance formed by Ecopetrol and Schlumberger.
A 3D seismic cube was shot during the first half of 2007. By the middle of 2008, the seismic cube had been loaded and interpreted and by October of 2008 the production had been boosted more than 50%.
The reasons….?. Two main reasons:
Of course: The second can not be properly implemented without the first.
By having a 3D seismic cube we were able to:
In other words it was possible to:
PEMEX Exploration & Production, with the technical support of Landmark Halliburton Mexico, implemented front-end-loading (FEL) methodology to define the optimum exploitation plan for the Teotleco oil field. FEL methodology, a relatively new approach in upstream project evaluation, considers the generation of multiple scenarios and analyzes the uncertainty and risk associated with each scenario.
A decision matrix was used to generate the scenarios in which several exploitation options were considered. One scenario was the current base case. Traditionally, base cases have been documented in a deterministic way using mathematical models, supported by exponential decline curves, for calculating production forecasts without considering the effects of individual wells and surface facilities. At the present time, however, there is commercial software that considers not only reservoir and well conditions but also considers surface operational conditions for production forecasts. This software leads to more realistic results.
Integrated Production Models(IPM) are very useful tools for calculating production forecasts and for optimizing field development. These models only provide a single possible solution each time they are run; but, now, deterministic models can be coupled with stochastic simulation programs to obtain probabilistic results.
Stochastic models require that uncertainties associated with each variable in the value chain (reservoir, drilling, productivity, facilities, economic evaluation, safety and environmental protection) be identified, characterized, and included in a new model, the Fully Integrated and Stochastic Asset Model (FISAM).
This paper shows the workflow to integrate reservoir (material balance), well (nodal analysis), and surface facilities conditions (pipelines and separation conditions), with an economics model (key performance indicators) using a stochastic simulator. The results of this workflow — which consist of production profiles, economic evaluation, and risk analysis —enable managers to improve project decisions.
The Teotleco FISAM model evaluated 15 exploitation scenarios. Review of the Net Present Value (NPV) and the associated risks in the value chain identified and then prioritized those scenarios that challenged the current base case. The flexibility and versatility offered by this approach for evaluating multiple scenarios facilitated the preparation of new updated PEMEX E&P exploitation plans. In these plans, which include new fields such as the Teotleco Field, the level of existing uncertainty will be recharacterized using new information generated as fields are exploited.
This paper aims at triple porosity reservoir with fracture and vugs, according to basic percolation principle the nonlinear well testing model with quadratic pressure gradient is established, considering wellbore storage and skin, for both the unsteady interporosity flow of the matrix to fracture and the unsteady interporosity flow of vugs to fracture. By use of variable substitution, linearizing the flow equation, the model is solved, and the Laplace space analytic solution is obtained, and then the real space solution is procured by use of Stehfest numerical inversion. So the pressure and the pressure derivative log-log new type curves are drawn up. Sensitivities of the type curves affected by different parameters are analyzed, including the influence of the quadratic pressure gradient coefficient ß, fluid capacitance coefficient and interporosity flow factor, which are the main parameters that can reflect the traits of fractured-vuggy triple porosity reservoir. The impact of (lower case beta) under certain conditions is extremely intense, and the dimensionless pressure error may be up to 20% and dimensionless pressure derivative error may be up to 30%. Especially for low permeability reservoirs and heavy oil reservoirs, there is a bigger ß; therefore the deviation of type curves between the linear model and nonlinear model is much obvious.
In the end, the example match explanation of a Carbonate well in Tarim oilfield is made, which shows that there are some differences in the explanation results between linear and nonlinear model, and the error of explanation results is very close to theoretical error, so the quadratic pressure gradient should not be neglected, and that the nonlinear percolation law is the actual flow law of oil in porous medium, and that the parameter values of nonlinear model explanation are more precise than those of linear model explanation, so the research on the nonlinear flow model and its application with quadratic pressure gradient should be undoubtedly strengthened and stressed. The results available in this paper can be further used in the study of the flow rule and the well test analysis of fractured-vuggy carbonate reservoir.