The performance of Pressure Transient Analysis (PTA) in heavy oil and low transmissivity formations is different from the conventional reservoirs, so the main objective of this work is to describe the pressure transient behavior in these low mobility-low transmissivity systems considering their impact on the main issues involved in, such as fluid viscosity, flow capacity, total compressibility and petrophysical properties. In this analysis, we present various well tests from many low transmissivity oilfields and some other heavy oil reservoirs in Mexico that produce from distinct depositional environments in sandstones and carbonates at different depths, onshore and offshore, with the objective of comparing and analyzing the pressure transient response with respect to time and the designing and execution of well tests in these types of systems. The main aspects related to the pressure transient behavior in low-mobility and low-transmissivity formations were analyzed, especially for the time required to reach the Infinite Acting Radial Flow regime (IARF) and subsequently, the pseudo-steady or steady state, where some properties are of paramount importance such as fluid viscosity, porosity, permeability, total compressibility, capillary pressure and net pay. The evaluation of the critical factors that rule the pressure transient behavior in low-transmissivity formations and heavy oils allows to identify certain patterns in transmissivity variations, determination of mean reservoir pressure, identification of reservoir heterogeneities and the corresponding influence of net pay on carbonates mainly. Furthermore, we suggest a series of recommendations about how to deal with this type of reservoirs when designing, executing and analyzing well tests for a better reservoir characterization through Pressure Transient Analysis (PTA).
The objective of the study was to estimate how much the mobility of a polymeric solution is affected at reservoir conditions, in an enhanced oil recovery process using polymer. This document describes the different techniques and methodologies to establish polymer solution degradation, and its effects over the expected behavior.
The analysis was performed using the results from 4 fall off tests at different stages of the injection process, the test were executed every three months after the beginning of the injection of the polymer solution, following the surveillance plan established. Other diagnostics techniques were also studied, in order to discard geologic features that could affect the injection process, among then: Hall plot diagnostics and temperature logging with fiber optics sensors.
The mobility of the polymer solution at reservoir conditions was determined. The affectation of the polymer solution is related to particular conditions of each section of the reservoir, meaning that minerals in the reservoir rock, and salinity of the connate water, could be the possible reasons why the polymer was affected, and exhibited a higher mobility compared to the design parameters. Later it was observed that the polymer mobility decreased over time, indicating that the polymer solution was no longer affected by in situ conditions.
To establish the performance of an enhanced recovery process using polymer, in the case of extra heavy oil reservoirs, it is necessary to evaluate the actual performance, and depend not only of the core test and simulation results. The analysis accomplished in this work was used to obtain important information necessary to asset feasibility, in the case of a larger scale implementation.
The determination of the preferential flow direction in a reservoir becomes a very important subject for the development of an oilfield, especially for the selection of the optimum exploitation strategy taking into account that porous media is a very complex environment in which representing the flow behavior of fluids becomes a tough task, mainly in carbonates where the distribution of fractures, lithology changes and diagenesis play a major role in this topic. Naturally Fractured Reservoirs (NFR) represent a great technical challenge for the petroleum industry because they behave as a heterogeneous medium with a strong influence of diagenesis, a term that encompasses fractures, dissolution, compaction, dolomitization, cementation and recrystallization to conform a reservoir with totally different distribution of properties. The dynamic data must be evaluated in order to match with the static model achieving a good reservoir characterization. In this paper we present a way to determine the preferential flow direction by the monitoring of the field through permanent real-time downhole gauges that allowed the identification of the interference between wells in a deep naturally fractured reservoir that originally did not show any degree of communication. Suddenly, after some producing time, the field demonstrated a great level of interference among wells and as a consequence, the determination of the preferential flow direction was possible through Pressure Transient Analysis (PTA) and Rate Transient Analysis (RTA).
Reservoir simulation history matching is one of the most complex and time consuming process, however, it ensures that the model developed is useful for forecasting and management decisions. By nature, an Integrated Asset Modeling model can be made up of hundreds of nodes, making it complex and difficult to manage if a proper methodology is not implemented to allow an effective history matching, especially when developing all the components of the IAM model. The purpose of this paper is to share lessons learned from a methodology that allows the development of reservoir models via material balance, proper matching of wellbore models and wellbore tests; calibration of the surface network and ultimately, history matching of an Integrated Asset Model, following rigorous quality assurance and quality check procedures. Issues addressed include: characterization of the reservoir-wellbore system, knowledge of main drive mechanisms, aquifer uncertainty, tubing flow assessment. The methodology enabled production history matching of 15 producing gas wells; ensuring that the IAM model developed is therefore a reliable forecasting tool. In addition, Simulation run time reduction was achieved by switching from a rate dependent constrained system to a pressure drop dependant system. Production history matching should precede any numerical simulation study, as it provides useful knowledge of the properties and characteristics of the reservoir-wellbore-surface network, leaving little room for adjustments, which constitutes an excellent starting point for numerical models; hence an IAM approach represents basis for the construction and quality check of more rigorous multi cells numerical reservoir simulation models.
The Orinoco Heavy Oil Belt, located in the southern part of the Eastern Basin of Venezuela, is considered the largest deposit of heavy oil in the world. It covers an area of 14 million acres and is characterized by having crude of low API gravity (from 7 to 10º), high viscosity (from 1,000 to 10,000 cp), high porosities (from 18 to 40%) and permeabilities that can reach 30 darcies. Heterogeneity is present in the Faja, there some areas with active bottom aquifers. On these particular areas an early water breakthrough has been identified in some horizontal wells.
A numerical simulation model with representative properties of an area of the Orinoco Heavy Oil Belt was defined to assess if the implementation of inflow control devices (ICDs) could reduce water production in horizontal wells. The numerical model contained a horizontal well where these completions elements were installed. The evaluation was made through a sensitivity analysis in which the configuration of the devices and some rock and fluids properties were changed. Additionally, the effect of the horizontal well length was studied as this parameter is relevant in the design and planning of horizontal wells in the Faja.
The results of this investigation indicated that the use of inflow control devices can be an effective technology to delay water breakthrough in areas where there is an active bottom aquifer with a good understanding of the geological properties and reservoir behavior. On other hand, this study showed how the differential increase in the cumulative oil of the wells decreases progressively as the horizontal well length section increases. An economic model was created to compare the different simulation scenarios.
This research serves as a basis for determining the feasibility of implementing inflow control devices as a water control technology and to obtain valuable information to designing the horizontal section of the wells.
The precipitation and deposition of paraffin wax during production, transportation and storage of crude oil are common problems encountered by the majority of oil producers around the world. During the last decade, the Barrackpore oilfield in Trinidad has reported wax deposition on nineteen (19) of its wells. This condition has been exacerbated due to the reduction of temperature, pressures and losses of gas which have allowed wax to separate from the crude oil, precipitate and deposit in the walls of tubings, thereby reducing their diameter and restricting the flow of oil through the system. The situation represented a serious problem for Petroleum Company of Trinidad & Tobago (Petrotrin), because it caused a reduction in the production levels and significant economic losses. This study was based on the necessity to find feasible solutions to minimize this problem. The research was focused to determine if there was influence of the resin/asphaltene ratio on wax deposition under laboratory conditions, to start an understanding process of the causative factors of these depositions. In addition, the influence of two (2) different wax inhibitors were studied for comparison, since it is understood they may behave as resins peptizing the asphaltene particles and keeping them in solution. To ensure the validity of this investigation, extensive bibliographical reviews were undertaken, followed by numerous laboratory tests such as SARA analysis, Cloud Point Tests and Wax Content Tests as methods to evaluate the crude oil and its behaviour under various conditions. The results showed that wax and asphaltene content are the controlling factors in the precipitation and depositions processes respectively.
Primary production of heavy oil from unconsolidated sand reservoirs is a process that is not well understood. Laboratory depletion experiments of sand packs, which mimic the field situation at a laboratory scale, show that production behavior of heavy oils under solution gas drive depend in a complex way on diverse parameter such as: depletion rate1,2, fluid properties3, porous medium propertiesi4,5, etc.
This work focuses on understanding the effect of the clay fraction in the sand pack on the recovery process. Experimental results from depletion tests at constant total volumetric production rate are presented. The porous media consisted of synthetic sands with different proportions of clay, except for one of the experiments, where reservoir sand was used. The oil was extra heavy crude (8°API) from the Venezuelan Orinoco Belt.
Pressure, pressure drop over the core, and oil and gas production were measured as a function of time. It was found that critical gas saturation and recovery factor increase with increasing clay content, whereas the supersaturation or the deviation from thermodynamic equilibrium decreases. This is interpreted in terms of an increasing number of nucleation sites at increasing clay concentration. More activated nucleation sites lead to more and smaller bubbles that allow a lesser mobility for the gas phase. Gas then becomes significantly mobile at larger gas saturations. This hypothesis is supported by previously published data from micromodel experiments doped with clay particles6.
The fact that critical gas saturation and recovery factor depend on the composition of the reservoir sand may strongly affect the evaluation of reservoir production capacity, because large regional heterogeneities related to clay content are often present in oil-producing "sands".
Primary oil production, as observed in heavy oil fields in the Venezuelan Orinoco belt, typically differs from that predicted using reservoir simulation. The field shows higher produced oil rates, lower gas rates, and slower pressure decline. At least, three different mechanisms contribute to the primary production process in volumetric reservoirs: (i) compressibility of the liquid phase, (ii) solution gas drive, and (iii) rock compaction. Because the liquid compressibility is much lower than the gas compressibility, the main contributing mechanisms are solution gas drive and rock compaction. However, the contribution of solution gas drive to the recovery process is generally larger than that related to rock compaction, and very often large uncertainty exists on the existence of this last mechanism and its contribution to primary recovery. Therefore, solution gas drive is commonly considered to be the main mechanisms in this type of reservoirs, at least early in primary production process.
Solution gas drive depends in a complex way on many variables7, including porous medium properties. Characteristics of the porous medium play an important role in the nucleation of bubbles during depletion6. By consequence, they also influence phase distribution and morphology. It has been reported that recovery factor increases as the number of bubbles formed during depletion increases8. A possible explanation is that the probability of coalescence decreases when more and smaller bubbles are present and that the gas phase remains immobile up to larger gas saturations. Large values of critical gas saturation and low gas mobility, which support this explanation, have been observed in depletion tests9,10.
The fact that porous medium composition affects heavy oil solution gas drive behavior is the main motivation for this work. We carried out a set of depletion experiments in sand packs doped with clay in different proportions. In order to emulate closer field situation, we also carried out an experiment with reservoir sand.
Numerous gas condensate well production data have shown that well productivity is severely affected when the bottom hole flowing pressure drops below the fluid dew point pressure. This productivity reduction is caused by liquid accumulation around the well. It is essential to take account of this ‘condensate blockage' effect when calculating well productivity since productivity losses can be significant.
Published laboratory, simulation and well-test data have shown that at bottom hole flowing pressure below the dewpoint pressure three regions are created with different liquid saturation.
Since the retrograde condensation has an important impact on gas condensate well productivity, the optimum exploitation of these reservoirs depends on the ability to diagnose condensate bank. Well test data has proven to be one of the few reliable field data of practical use to detect the existence of retrograde condensation. In Santa Barbara field, the biggest Venezuelan gas-condensate field, application of the latest practical well-test analysis methods contributed to demonstrate the presence of velocity stripping and retrograde condensation despite conventional reservoir engineering analysis did not show such phenomena.
The paper discusses how the use of two and three radial composite model helped to gain a better understanding of Santa Barbara condensate reservoir behaviour when 1999 to 2001 well tests were reinterpreted. As velocity stripping was detected, near well bore relative permeability measurements were proposed in order to take account of the phenomena which occur at high flow rates when calculating well productivity in the field-scale simulation model.
Santa Barbara field is the biggest gas condensate field in Venezuela. In this area, PDVSA concentrates most of it operational activity due to its high potential in gas and light oil. Reserves are as big as 6060 MMbls of liquid originally in place, and the accumulative production at December 2001 is approximately 530 MMbls.
During the last years, it has been observed with great concern that the reservoir pressure of Santa-Barbara field has been declining dramatically. While the initial pressure was 12000 psia at a datum elevation of 15800 feet-ss, nowadays the average reservoir pressure and temperature is around 7400 psia and 290 °F, respectively. As the bottomhole flowing pressures of some gas condensate wells started to show values below the dewpoint at the end of 1998, gas productivity impairment caused by retrograde condensation became an issue of great deal due to its negative impact on the recoverable reserves.
Numerous laboratory, theoretical and field studies have been conducted over the last forty years to try to understand condensate flow behavior. The data collected from these studies have shown that when the pressure around a well drops below the dewpoint pressure, retrograde condensation occurs and three different mobility zones with different liquid saturation are created within a radius less than 100 feet. An outer zone away from the well with initial liquid condensate saturation, a zone closer to the well with increased immobile condensate saturation and low gas mobility, and a near wellbore zone with high capillary number (velocity stripping) which increases the gas relative permeability. This increment on gas mobility at the immediate vicinity of the well compensates much of the lost caused by the condensate. It has been found that these zones are very important when calculating well deliverability1,2.
The analysis of well tests on gas condensate wells with retrograde condensation is usually based on either the two or three-zone radial composite model3. This model is based on a simplified geometry of the three regions described above. This paper explains how well test analysis was one of the few reliable field data of practical use to detect the existence of retrograde condensation and velocity stripping around gas condensate wells in Santa-Barbara field.