Carpio, Gelson (PDVSA Gas & Oil) | Rodriguez, Fernancelys Del Carmen (PDVSA Gas & Oil) | Khan Torres, Karem Alejandra (Petroleos de Venezuela S.A.) | Contreras, Anairt Lisseth (Petroleos de Venezuela S.A.) | Campos, Luis S. (Petroleos de Venezuela S.A.) | Idrogo, Crimilda (Petroleos de Venezuela S.A.) | Labastidas, Eduardo (Petroleos de Venezuela S.A.)
El Carito-Mulata and Santa Bárbara fields are located in Eastern Venezuela in the Maturín sub basin and cover almost 300 km2. The asymmetrical anticline of the reservoirs is the result of different tectonic regimes alternating compressive and extensive periods from the late Cretaceous to the Middle Miocene. The fields are producing 240,000 STB/D and their OOIP is estimated to be around 6.5 MMMSTB. The variation of the vertical fluid distribution is predominant. There is a light oil (condensate) at the top of the structure, black oil at the base and free water at different levels in the reservoirs. This vertical fluid distribution is not well represented in the
dynamic simulation model, which increases the uncertainty on any prediction or elaboration of the production plan.
The main objectives of this study are the determination of the original fluid contacts and the construction of a fluid model, which takes into account the free water presented in the reservoirs. This model can also define the vertical and lateral extension of the oil fields, indispensable for the reserves estimation.
The integration of the different kinds of static and dynamic information of 149 wells was necessary in order to obtain a well-supported fluid distribution model.
The analysis of the large number of data allowed defining the geometry of the Tar mat (asphaltene content > 20%), which is folded/faulted according to the structure and considered as a sealed layer in reservoir conditions, with thicknesses ranging between 300 and 500 feet. The irregular Tar mat surface limits the reservoirs and controls the free water levels in the fields. This new fluid distribution model was included at the numerical simulation model matching all the wells information about water or type of oil that has been produced or tested.
The recoveries from the wells in an oilfield do not usually form a perfectly lognormal distribution. So the log probability plots of the recoveries usually do not exactly conform to the straight line that signifies lognormally distributed data. Certain types of deviation from the straight line can provide useful information about the oilwell recoveries.
A set of recoveries may differ from the lognormal
and all these cases have characteristic effects on the shape of the log probability plot. Some illustrative field cases are presented.
A quick review of the quality of a set of oil recovery figures can be made by preparing a log probability plot. Certain characteristic shapes of the plot may indicate that the data is incomplete or that it is not homogenous and should be disaggregated for further analysis.
A variable is said to be lognormally distributed if the logarithms of the variable are normally distributed1,2,3. Many reservoir properties have been found to be approximately lognormally distributed, for example formation thickness, core permeabilities, oil recoveries and field sizes1. This paper explores the significance of certain types of deviations from the lognormal.
A log probability plot is similar to a normal probability plot except that a logarithmic scale is used to plot values of the variable. The cumulative frequency distribution of a lognormal distribution forms a straight line when displayed on a log probability plot. But for real oilfields, the oil recoveries usually are not exactly lognormal, and deviate from the straight line.
A plot may deviate from the straight line simply because the data is not exactly lognormal: the distribution may be skewed, with one tail longer than the other, or the peak of the distribution may be higher or lower than the lognormal. But the data may deviate from the straight line because it is incomplete. For example, the field may have had several owners, not all of whom were equally careful about recording oil recoveries. Also, the data may deviate from the straight line because it is not homogenous. For example, if the oilfield includes different reservoirs with very different producing characteristics, then it may be appropriate to separate the oil recovery data into sub groups before making cumulative distribution plots.
This paper presents sets of data which show how some of these types of deviation can be identified from the log probability plot.
Ideal Normal Distributions
Figure 1 shows the frequency distribution of three normal distributions with different means but the same standard deviation. These are examples of the famous bell curve or Gaussian distribution. Since the distributions are symmetric, for each distribution the peak represents the mean. It can be seen that distributions with different means are displaced laterally on the plot. Figure 2 shows the frequency distribution of three normal distributions with different standard deviations but the same mean. It can be seen that distributions with different standard deviations have different widths.
With the main objective of reducing working times of rig equipments and this way costs for operator companies an insertable Progress Cavity Pump (PCP) has been developed. This pump is designed to be anchored in the top (by cups) and with a 2 7/8?? anchor in the bottom section.
This kind of pumps can be installed in wells where beam pumped systems were installed before, and vice versa, avoiding the production string pulling. So if a change from a beam pumped system to PCP system is required, utilizing this new design, the rig activity would be limited to: pulling rod string, changing the pump and installing the string again. If a fast mounting rig is used to realize the replacement, the working time could be shorter.
Other advantage of insertable PCP is that the production flow rates has been increased, obtaining a several range of applications.
This paper presents a short technical description of and some tests of insertable PC Pumps in different wells of Guadales and Lomas Del Cuy oilfields (Area Guadal - Las Heras - Repsol YPF). Theses pumps were tried at different depths, stresses, hydraulic powers and other well conditions in order to demonstrate the same performance of traditional PC Pumps.
An economical analysis exhibits the convenience and some qualitative benefits of installing insertable PC Pumps in a certain range of wells, depending on their flow rates, especially when a beam pumped system will be replaced for a PC Pumped system. Besides it provides a future projection of insertable PC Pumps installations in the mentioned oilfields.
EL GUADAL oilfield is located in Santa Cruz north Argentina area. Its well production is poor so we are forced to make continous analysis in order to reduce costs.
Nowadays, the extraction costs are high so the possibility of changing the elevation system without moving the tubing was analysed. This would allow a lower cost by intervention and a more optimised production due to more well servicings throughout the year.
This document deals with the main economic and technical aspects of the change of the elevation system from mechanic pumping into progressive pumping which decreases the well maneuvre costs in EL Guadal oilfield, Las Heras-Santa Cruz-Argentina.
The introduction of a Flush By equipment would also be helpful because it does not require tubing movement.
Technology improvements continue to advance the capabilities of coiled tubing directional drilling (CTDD). Alaska's North Slope, with its prevailing dedication to expanding the technological envelope, has served as a testing ground where advanced CTDD techniques mature into economically viable systems.
Even after over 500 successful CTDD sidetracks on the North Slope, impetus remains to further improve this economical drilling technique. Through a close working relationship between field operator and the service company, significant research and development has led to the introduction of novel tools and services to overcome the intrinsic hurdles of conventional CTDD.
Through a process of miniaturization and innovation, small-diameter systems have been developed for CTDD. The most recent introduction of tools and services includes rib steering technologies, bidirectional wireless mud pulse telemetry, gyro-based MWD services, and ultra-slim, high-resolution, real-time resistivity.
Straighter, longer horizontal laterals, improved steering, and real-time resistivity in openhole sizes as small as 2 3/4-in. ID has been achieved, consequently improving precision in geosteering within the narrowest of payzone.
This paper highlights two case histories describing CTDD technology, real-time formation evaluation, and multilateral drilling processes used to access previously unreachable oil-bearing rock on Alaska's North Slope. While proven in this region, CTDD advances are applicable in other mature fields for the economical extraction of additional reserves.
Ever since CTDD started off in the year 1994 in the North Slope of Alaska, it has become an ongoing desired method for slimhole re-entry from existing wells in the region to access additional reserves. The continuous use of CTDD for re-entry in Alaska, because of the operators' persistent and innovative culture, has made it a proving ground for newer drilling and completion techniques and advanced bottomhole assemblies (BHAs). It has proven itself as the most efficient and cost-effective method of sidetracking and re-entering existing wellbores with cost savings of up to 40% compared to conventional rotary drilling in the region.5
What started off as selecting simple candidates for re-entry with CTDD has now evolved several folds into routine selection of complex candidates presenting just as complex drilling techniques. The vast experience gained in the region and the development of advanced BHAs have made returns from these once "hard candidates?? an economically sound and successful CTDD campaign.
A number of these candidates have an existing 3½-in. tubing, which required the development of advanced tools in sizes as small as 2 3/8-in. to re-enter through these wells without a tubing retrieval operation. The development and usage of these tools in the 2 3/8-in. size redefined the meaning of slimhole drilling and opened up drilling opportunities to many additional wells.1
Key benefits gained from the development of such CTDD tools is the acquired knowledge and experience in re-entry and the drive to push the application into complex and sometimes fragile formations such as those found in the Kuparuk River Unit.
The dynamically overbalanced drilling (DOD) technique-where the drilling fluid is underbalance, yet the surface pressure is adjusted to maintain at-balance condition on bottom-also sometimes known as the managed pressure drilling technique, is a significant improvement in successful drilling technology in such fields. Monitoring of downhole conditions to maintain at-balance conditions, especially the annular pressure, with fastest data update rate, and the ability to steer the BHA as required without any pressure fluctuations were necessary to drill using the DOD technique.2 These BHA requirements apply also to the underbalanced drilling candidates in Alaska.
Fast update rates could only be achieved by an e-line system of steering tools, which had to be in the 2 3/8-in. size to re-enter a number of these complex wells and formations. Hence, the application led to the development of e-line BHAs with downhole dynamics, pressure monitoring, real-time downhole weight on bit, and the functionality to steer and navigate the wellbore in the right path while on bottom drilling.
Deep offshore oil production demands very high investments (CAPEX) so its development must rely on a careful planning. This frequently takes place in a setting with very limited amount of information due to high costs of appraisal operations. The figure becomes even more complicated when heavy oils are the target: low energy reservoirs require water flooding which, in turn, reflects in low recoveries and excessive water handling, not to mention other production problems.
This paper highlights different simulation studies that have been performed in order to set up an economical development plan for a 16 API 1700m water depth oil reservoir offshore Campos Basin. The main reservoir consists of a high thickness turbidite channel crossed by a N-S fault whose hydraulic conductivity is the main uncertainty. Vertically the reservoir is composed of three zones, where the upper one has a gas cap partially in contact with the two bottom ones. These structural complexities required a detailed study for positioning injectors and horizontal producers based on a decision tree analysis. The impact of other uncertainty variables was also identified and studied: horizontal permeability, vertical to horizontal permeability ratio, water-oil relative permeability and productivity index. Particular attention was given to the injectivity decline due to the planned produced water re-injection. Vertical and horizontal injection wells performances were compared in a scenario under strict geomechanical restrictions. The simulation model was also used to evaluate the possibility of developing marginal areas close to the main reservoir body.
The study leaded to a robust strategy for the water injection scheme. Risk and marginal reservoir analysis helped the decision of the features of the future production system in terms of oil and liquid processing capacity and adoption of some flexibility to make feasible the future development of marginal areas.
Exploration efforts offshore Brazil have been indicating important heavy-oil discoveries in deepwater reservoirs. The economic exploitation of these reservoirs presents technological and economic challenges that must be addressed. Therefore, the initial development plan must be defined through a detailed optimization study, considering economic indicators, oil recovery and risks 1, 2.
The development of Marlim Sul Field was planned in four modules: module 1 started in 2001 and has two production units producing 200,000 bopd. Module 2 will start the production through P-51 platform in 2008 and modules 3 and 4 are in development phase. These two last areas present special difficulties since they have oil viscosities greater than 20 cP at reservoir conditions. The introduction of new technologies could mean the solution for the feasibility of these projects.
Thus a research project was developed in the scope of Petrobras Offshore Heavy Oil Technological Program (PROPES) that comprised the following objectives: optimization of the drainage plan, taking into account the application of extended horizontal wells (around 800 m), evaluation of the use of high capacity plants for the processing of produced fluids and evaluation of the performance of artificial lift methods comparing the efficiency of gas lift and electrical submersible pumps. Studies related to the impact of the main N-S fault of the reservoir on the development plan, the consideration of uncertainties on rock and fluid properties and the analysis of the injectivity decline had also been performed.
This work focuses on the optimization of a development plan for Marlim Sul Field's third and fourth modules aiming at establishing a robust strategy encompassing all the geological and technological uncertainties.
Reservoir General Data
Marlim Sul Field is located in Campos Basin, distant approximately 120 km from north coast of Rio de Janeiro State, Brazil. It stands in water depths varying from 800m to 2600m in an area of 572 km2. Figure 1 depicts the field location.
Rodriguez, Fernancelys Del Carmen (PDVSA Gas & Oil) | Lopez G., Leonardo (Petroleos de Venezuela S.A.) | Bello, Joaquin Antonio (Petroleos de Venezuela S.A.) | Skoreyko, Fraser A. (Computer Modelling Group Inc)
The Carito-Mulata field is located in eastern Venezuela. This field is ranked as a giant oil producer because of its 240,000 STB/D current oil production and its 6.5 MMMSTB original oil in place. It is possible to observe a significant compositional gradient from seventy-five fluid samples taken at different depths, over a column of fluids of approximately 4000 feet thick. This complex system changes from a gas condensate at the top to an under saturated black oil down the flank. The depth of the Gas-oil contact is estimated at 14,040 feet.
The Carito-Mulata field has been operated and characterized traditionally in four blocks (Central, West, North and South). The fundamental goal of this study is to establish a compositional model that can represent areally and vertically the complex fluid system using an Equation of State (EOS), which represents a big challenge considering the huge number of laboratory experiments. This EOS will be used for EOR simulations under gas and nitrogen injection processes.
The Peng-Robinson EOS was used to match the PVT experiments. Included in the matching parameters was the variation of the saturation pressure of the gas condensate due to nitrogen injection. A swelling test using black oil crude with the injection of gas condensate was also fitted, as well as stacked core miscible experiments of gas condensate displaced by nitrogen injection. Finally, a set of PVT tables were generated for the compositional numerical reservoir simulator.
The most important result that has been obtained of this project is to prove that a single Equation of State can model the complex thermodynamic behavior of three areas that were previously modeled as isolated. Considering that the field could be under nitrogen or natural gas injection, the Equation of State generated in this study will allow the numerical simulation to predict the impact of these processes on the ultimate hydrocarbon recovery.
The Carito-Mulata field is located in the Eastern Basin of Venezuela, about 50 km west from city of Maturín, Monagas state. It is defined an asymmetrical anticline witch is characterized by a production of fluids whose composition varies with depth, from the condensate gas, at the crestal part of the structure, to under-saturated black oil in deep areas.
The field is situated in the northern part of Monagas State, between the El Furrial and Santa Barbara oilfields. Its production started in 1988 with the MUC-1E well. The reservoirs present a considerable level of heterogeneity as a result of a combination of complex geological events, including compressional tectonics, faulting and a diversity of sedimentary environments.
At the present time, the central and western blocks of the field are subject to natural gas injection, the northern block undergoes water injection while the southern one flows naturally.
Despite of the good definition of the fluid distribution throughout the field, the actual compositional modeling was still carried out in an isolated way previous to this study.
In order to create an integrated simulation model taking into account the observed communication between blocks, it is indispensable to have a correct areal and vertical fluid characterization based on revision and validation of the available laboratory data. These include PVT studies, production data, RFT logs, etc. In case of EOR process modeling, it is necessary to also consider the special fluid tests (swelling test and displacement measures on cores) which permit the evaluation of the injected gas effect on the original fluid properties in the reservoir, particularly at the saturation pressure.
The compositional modeling which is the subject of the present paper was aimed at reproducing the fluid behavior under reservoir and surface conditions through the equation of state (EOS) and experimental data. The objective is optimizing the field exploitation strategies considering the injection of nitrogen or natural gas.
Original Oil In Place (OOIP) calculations based on material balance methods are strongly influenced by data uncertainty. Although some research is available in literature, usually the effects of data uncertainty on material balance calculations are rarely considered and quantified in most studies. This work presents an approach to properly quantify and account for the impact of reservoir pressure and PVT data uncertainty on material balance calculations under different drive mechanisms and using different material balance methods. This study allows reservoir engineers properly select the most suitable material balance method when uncertainty on reservoir pressure and PVT data is significant.
In this work, two different methodologies are proposed. First, a sensitivity analysis was conducted using generated realizations of reservoir pressure and PVT data to evaluate their effect on material balance calculations. Second, a more robust approach was proposed using experimental design and analysis of variance to systematically evaluate the influence of reservoir pressure and PVT data on material balance calculations in an optimal and integrated fashion. In both methodologies, different material balance methods were used and computed OOIP were compared to reference values from a conceptual reservoir model with known PVT data and simulated reservoir pressure. A MATLAB-based program, with graphical user interface, was coded for this purpose1.
Application of the proposed methodologies allowed to determine and quantify the most significant parameters that influence material balance calculations. Interestingly, the most important parameter was the selected material balance method used to compute the OOIP. More accurate results were obtained using the traditional graphical method (F-We vs. Et) for volumetric oil reservoirs with minimal pressure and PVT data uncertainty. In those cases with moderate to significant water influx and gas cap, and some uncertainty on pressure and PVT data, less accurate original oil in place was obtained when graphical methods were used. Reservoir pressure uncertainty was the most significant parameter on the material balance calculations. Gas-oil ratio uncertainty was also significant. Oil and gas gravity, and reservoir temperature were less significant.
Material balance is a simple and one of the most important reservoir engineering tools. Calculations require production/pressure data, PVT data, and aquifer parameters, so that original oil in place and drive mechanisms can be quantified. Data quality is an important issue in material balance calculations. Uncertainty due to data errors can be found in field production data, measured PVT properties, and average reservoir pressure.
Usually, it is expected that oil and gas production are measured with confidence since industry revenues are based on oil and gas sales, and consequently error in production data can be considered minimal. However, reservoir pressure is uncertain since limited well measurements are usually available and averaging procedures might introduce some uncertainty in the computed reservoir pressure history. PVT data can be also uncertain since some reservoirs have no representative fluid samples for a complete PVT analysis and correlations are used instead for material balance calculations.
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.
Successful acid stimulation requires a method for diverting an acid across the entire hydrocarbon-producing zone. Because most producing wells are not homogeneous and contain sections of varying permeability, being able to completely acidize the interval is a major problem. This paper describes the use of a new low-viscosity system that uses a relative permeability modifier (RPM) that diverts acid from high-permeability zones to lower-permeability zones and inherently reduces formation permeability to water with little effect on hydrocarbon permeability. This system has been used effectively offshore Mexico with success for more than two years. The cases presented in this paper show the first application in a low-permeability carbonate formation where oil production was increased significantly compared to previous traditional acid treatments using conventional diverters.
The other important feature of this work is that the downhole conditions were high-pressure/high-temperature (HPHT). Details from the jobs using this new RPM acid-diversion system will be presented showing pre- and post-job production results.
Matrix acidizing enhances well productivity by reducing the skin factor. The skin factor can be reduced if near-wellbore damage is removed or if a highly conductive structure is superimposed onto the formation. In either case, the result is a net increase in the productivity index, which can be used either to increase the production rate or to decrease the drawdown pressure differential. Although the benefits of an increased production rate are evident, the benefits of reduced drawdown are often overlooked. Decreased drawdown can help prevent formation collapse in weak formations, reduce water or gas coning, minimize both organic and mineral scaling, and/or shift the phase equilibrium in the near-wellbore zone toward smaller fractions of condensate or solution gas. A reduced drawdown pressure can also help ensure that a greater percentage of the completed interval contributes to production.1
In attempts to achieve uniform placement of acid across all layers, various placement techniques have been used.2 The most reliable method uses mechanical isolation devices (such as straddle packers) that allow injection into individual zones one at a time until the entire interval is treated. However, this technique is often not practical, cost-effective, or feasible. Without a packer, some type of diverting agent must be used.
Typical diverting agents include ball sealers, degradable particulates, viscous fluids, and foams. Although these agents have been used successfully, all have potential disadvantages and none address the problem of increased water production that often follows acid treatments. Therefore, it would be a major advantage to have a material that could inherently decrease the formation permeability to water while also providing diversion.
One method of controlling water production uses dilute polymer solutions to decrease the effective permeability to water more than to oil. These treatments may be referred to as relative permeability modifiers (RPM), disproportionate-permeability modifiers, or simply, bullhead treatments. The latter name is so called because these treatments can be bullheaded into the formation without the need for zonal isolation. RPM systems are thought to perform by adsorption onto the pore walls of the formation flow paths.3-5
This paper presents the development and field implementation of a state-of-the-art bottomhole assembly (BHA) program using the industry's first generic algorithm based on Lubinski's equations. The strengths of the new BHA program are accuracy and computation efficiency, as compared to the conventional finite-element based BHA programs. In addition, the new program integrates static and dynamic models so that users can run both models in the same application. Using the new algorithm, the static model is designed mainly for directional drilling applications, such as optimal BHA design for maximum steerability, bending moment calculations to minimize fatigue failure, and BHA sag corrections to improve survey quality. The dynamic model is based on a hybrid of analytical and finite-element methods to calculate the critical rotary speeds of the BHA. This paper describes the significance of applying these features in a user-friendly application to maximize drilling performance.
Bottomhole assembly (BHA) modeling is always an essential part in directional drilling. A state-of-the-art BHA program enables many critical features, such as (i) designing a BHA to optimize directional performance, (ii) optimizing stabilizer locations to minimize vibration and increase downhole tool reliability, and (iii) improving survey data by correcting the BHA sag. Since the 1950s, several different methods have been developed and applied in the drilling industry to build the BHA models. 1-7
In general, the challenges encountered in developing a computationally efficient, flexible, and accurate BHA model can be summarized as follows:
The most commonly used method in BHA modeling is probably the finite-element method because it is easy to develop and use. However, to the knowledge of the author, many commercial finite-element based BHA programs are still based on the small deformation theory. As a result, they have been shown to lack the accuracy required to model steerable assemblies, such as motor or rotary steerable systems. Finite-element modeling is also cumbersome in handling the collars and wellbore contact. To accurately model steerable systems, the semi-analytical methods are usually required, but semi-analytical methods are inflexible and difficult to program. They are often designed to analyze some specific BHA models and are limited to BHAs with rather simple configurations.
The objectives of developing a state-of-the-art BHA program include the following: