Bellorin, William Enrique (Petrobras Energia de Venezuela) | Castillo, Jose Antonio (Petrobras Energia de Venezuela) | Lopez Kovacs, Sonia Isabella (Petrobras) | Riera, Ladimir Alberto (Petrobras Energia de Venezuela)
The study area has produced over 457 MMBbl of oil since its discovery in 1954. This study is focused on the R sand reservoir, one of the most important of the area. The original oil in place (OOIP) is 140 MMBbls and before the begining of the project, the accounted recovery of OOIP was 7.2%.
The field reactivation was performed after a thorough analysis that included a geological model review and creating a numeric simulation model. This resulted in an increment of the field production which reached up to 7000 Bbls/d of oil and an enhanced recovery factor of 13.6% by March 31st, 2005.
The main producing zone of the study area comprises Early to Mid Miocene (Oficina Formation); it is interpreted as interbedded sandstone, deposited in a fluvial environment with marine to shallow marine influence. Core analysis in one well shows that R sand was deposited in coastal plain influenced by tides and characterized by connected channels and outlets. The 3D seismic information available in the area made it possible to accurately define the structural model. After defining the static model and with the support of the engineering study, the reservoir development plan could be defined, which was oriented to improve and to increase the field productivity. It mainly consisted in drilling horizontal wells where succesful results were obtained after drilling and completing seven wells. This shows the impact of this type of wells in terms of economic benefits resulting in an increment in production and the recovery factor.
The study area, is located approximately 400 km to the south east of Caracas, in the Area Mayor de Oficina. Structurally, the field is located in the southern flank of the Eastern Venezuelan Basin, in the foreland platform zone (Parnaud et al., 1995) (Fig. 1). The reactivation project of the R Sand reservoir resulted from a previous study of characterization that allowed elaborating a plan of operation constituted mainly by horizontal wells producing with high volume electrical submersible pumps from 7,000 to 20,000 BFPD. To date 7 horizontal wells throughout the reservoir have been drilled; they produce between 300 and 1100 BPPD. At the end of 2003 an electrical submersible pump with capacity to produce 20,000 BFPD was installed representing the first in its class of Petrobras in Venezuela. The definition of the stratigraphic and the structural model as well as the simulation of the reservoir played an important role in deciding the location of the horizontal section of wells. The reservoir is delimited to the south by a main fault east-west oriented, that has a vertical throw of 400 feet, to the north a water oil contact at -6760 feet, to the east by a secondary fault of direction NE-SO of 280 feet of vertical throw and to the west by a structural closure against the main fault of the area.
The producing sands of the Oficina Formation of which the R sand is part of, are included in a foreland megasequence of the Maturin Sub basin which in turn is part of the Eastern Venezuelan Basin (Fig. 1). This Neogene foreland basin is superposed to a Mesozoic passive margin (Di Croce, 1995). The Eastern Venezuelan Basin is subdivided in the Guárico and Maturin Sub basins; they are separated by the Anaco fault system (Di Croce, 1995). The South and east limits of the Eastern Venezuelan Basin are, respectively, the Guayana Shield and the Deltana Platform (Di Croce, 1995). The Maturin Sub basin constitutes the main hydrocarbon unit of the basin. To the south of this Sub-basin, the important reservoirs are in the Merecure and Oficina Formation (Fig.2), with seals of shale within these units overlain by an important and extensive seal of shale of regional character corresponding to the Freites Formation (Upper Miocene). The API gravity of the crude is very diverse, varying from light crude to heavy and extra-heavy crude. As to the oil systems of the Maturin Sub basin, one of the most important ones is the denominated Guayuta-Oficina that is related to the fields of the South flank of the sub basin and includes the main source rocks of Late Cretaceous age, Querecual and San Antonio Formations.
Margarita field is one of the most important gas fields in Bolivia, not fully developed yet. The field development is to be completed in the near future and as part of the facilities to be constructed, it is included the installation of a slug catcher. The slug catcher situated at the end of the pipeline is intended to separate the phases and to provide temporary storage for the liquid received. Slug Catchers should be designed to take care of a slug.
The selection between the "Finger Type?? and "Vessel Type?? would be thorough the economical aspects and the characteristics of the equipment that best adapts to the conditions of the site.
The slug volume of the Margarita Field, calculated for a gathering system of 13 wells, being the outermost 30 Km. apart from the Plant, resulted in 26,35 m3 with a design pressure of 2025 psig.
The "multiple-pipe?? slug catchers ("Finger Type??) equipment is the most common equipment to handle slug volume, it is efficient and the operation is well known, however the common practice recomends that for volumes less than 100 m3, it is better to use the "vessel type?? (this would be our case with 26,35 m3.) According to the rule of thumb the selection should be "Vessel Type??, where 18 MMsm3/d is considered the gas flow for the design, that results in a diamenter of 102 inches by 14 meters long and a weight of 150 tons for the equipment size.
The "finger type?? design from the equipment manufacturers could handle the same slug volume but the size is four fingers with a diameter of 40 inches by 10 meters long. The finger type needs 16 field welds and the weight is 80 tons. The equipment results in an easy assembly, of simple operation, smaller and lighter that facilitates transportation.
The Ex-Work delivery Cost and the equipment delivery to the site favors the "finger type?? over the "vessel type??. The installation cost for the vessel type is cheaper than the finger type but it is not enough as to favor the vessel type because if we add Ex-Work delivery and Installation costs, the finger type saves 30%.. The vessel type does not fulfill the savings expectations.in the Margarita Field Project ("onshore??).
Additionally one more characteristic in favor for the finger type is the weight where the finger type does not risk transportation, where as the vessel type has transportation risks because the existing roads have only one lane that allows the passing of equipment less than 90 tons. The vessel type has 150 tons with a pressure design of 2025 psig; and if the pressure design would be 1500 psig, the weight would be of 120 tons.
After taking in consideration all the points in favor of the finger type (the multiple-pipe slug catchers), it is recommended to be installed in the Gas Treatment Plant (GTP).
The Margarita Project calls for a field development, covering the flow lines, main header, slug catcher, gas dehydration and dew point control, condensate stabilization, and water treatment. This system is known as the Gas Treatment Plant (GTP), which shall produce a relatively gas stream and condensate.
The gathering system of the Project consists of individual flow lines connecting 13 wells with three headers at a new gas plant. The three headers will directly combine the well flow to the slug catcher or the individual well flow to either the test separator or to the existing Margarita plant.
The Gathering System considered the production facility consisting of 13 wells at ten sites in the Margarita field connected by 120 km of new 8-inch gathering pipelines, plus 30 km of existing 8-inch gathering pipelines.
The Aguada Pichana field is located in the center of the Neuquén Basin in the province of Neuquén, being at present, one of the main gas producers in Argentina. The completion programs of Aguada Pichana wells imply the stimulation of Middle Mulichinco Formation (primary target) through hydraulic fractures.
Mulichinco Formation is 30 to 80 meters thick and has a variable permeability throughout the pay zone. The gas drainage from the best permeability zones causes a differential depletion in reservoir pore pressure, affecting by consequence the mechanical properties of the rock in its whole thickness. This petrophysical and mechanical behavior of the reservoir, added to the possibility of finding free water in the lowest part, makes it difficult to reach the best results by means of a unique fracture.
Within the optimization process that is followed in the development of this field, the implementation of a strategy of selective stimulation, through the pumping of two hydraulic fractures directed to reach different challenges, provides the best option for obtaining better results. In order to stimulate the base of the zone, the first stage of fracture includes an aggressive design of high conductivity with the aggregate, in some cases, of Relative Permeability Modifier additive (RPM) in the frac fluid for water control. In the top of the zone, the second stage is characterized for being a fracture of greater length, diminishing the convection effects.
This work summarizes the designs, operational planning and results of the new methodology of implemented hydraulic fractures.
Aguada Pichana field is located in central part of the Neuquen Basin. The field produces gas and condensates from the sandstones of Mulichinco formation (Valanginian to Hauterivian). The Mulichinco is characterised by a relatively thick sedimentary column, ranging from 150 to 250 meters, with 30 to 80 meters of pay zone, from South to North. In Aguada Pichana, the reservoir level being produced is composed of sandstones deposited in a fluvio-tidal to littoral environment, characterized by low to very low permeabilities, partly belonging to the Tight Gas Reservoirs category and thus requiring specific stimulations through hydraulic fractures.
Aguada Pichana field conditions have changed through its productive life. The Middle Mulichinco formation is producing gas from sandstones at 1650m depth with an average permeability varying from 0.1 to 5 mD. Reservoir pressure has fallen from the original 2500 psi to 900 psi in the most productive areas.
The following section is a detail of possible reasons explaining the low production post-frac flows obtained in wells that were completed along the 2004-2005 completion campaign.
Review of Previous Treatments
In Aguada Pichana field, the Standard well-completion program included the stimulation of Middle Mulichinco Formation through a one-stage hydraulic fracture.
In general, although the net productive interval to stimulate was greater, only 10-15 meters were perforated, in order to stimulate Mulichinco zone in a single stage. Simulations with 3D models were done in order to predict downward fracture growth into the underlying sands containing movable water. After fracture stimulations, the perforated interval showed to be in the most convenient area to start up fracturing. The design volume was fit to limit the vertical growth of fracture, without growing down into possibly water bearing levels.
In the oilfield industry, many resources have been allocated to develop lightweight slurries that will reduce the equivalent hydrostatic pressure against low-pressure formations and achieve successful zonal isolation while performing a cementing job. However, to comply with the standard recommended practices for cementing operations, it is crucial to maintain a progressive rheological and density trend from the spacer up to the tail slurry. Centralization and friction pressure play another very important role in achieving a suitable design and have to be considered during the design stage as well.
This paper describes how a lightweight spacer with 0.88 g/cm3 (7.3 lbm/gal) density was developed and its important contribution while performing a cementing job in a depleted zone.
One of the main contributions is the possibility for decreasing the hydrostatic pressure and the equivalent circulation pressure by increasing the spacer column length. By increasing the column length, additional mud can be returned to the surface, which would represent an important cost savings in cases where the mud is expensive and could be reused.
Not using nitrogen to reduce the hydrostatic pressure also contributes to savings in operational costs and facilitates the job execution and logistics. Eliminating the use of diesel in the spacer to reduce its density minimizes the possibility of having incompatibility and contamination problems with the cement slurry. The reduction of the ecological impact is also an issue to consider.
Finally, we might be able to evaluate features and benefits of this technology as well as its future applications in the industry.
The Cantarell oil field in the Gulf of Mexico is located in the Bay of Campeche. It is the largest oil field in the area with an average production of 317,975m3/d oil (2 million BOPD) from the Brecha formation. The formation is in the Paleocene and Cretaceous zones with a thickness from 150 m to 900 m (492 ft to 2,953 ft) and greater than 5-µm2 (5-darcy) permeability.
After producing for more than 25 years, this field has been depleted. Several years ago, wells were drilled without any returns (total lost circulation) using oil-based drilling fluids with densities as low as 0.88 g/cm3 (7.3 lbm/gal). These levels do not even reach the surface [1,500 m (4,921 ft)] below the surface] due to their low integrity where the formation pressure gradient is equivalent to 0.55 g/cm3 (4.6 lbm/gal) and the fracture pressure equivalent to 0.65 g/cm3 (5.4 lbm/gal). These very low pressure conditions resulted in considering the use of ultralight cement slurries with similar densities to the drilling fluid to bond the production casing during the final stage of the well construction.
The use of ultralight cement slurries has also created the necessity for the evolution of the spacers used during the cementing operations in terms of density.
The Need for an Alternative Ultralightweight Spacer
In accordance with the recommended minimum criteria to ensure a good cementing job, the design of an alternative spacer represented a challenge for cementing jobs in the Cantarell field.
One of the mayor economical impacts in a Project of artificial lift system shift is the associated cost of energy moreover the maintenance and well intervention must be considered. These variables are reflected as addition on the final artificial lift cost selected.
This study was accomplished based on experience at the Teca and Nare fields operated by Omimex Colombia where an artificial lift system shift was performed from Rod Pump (RP) into Progressive Cavity Pump (PCP), achieving significant savings in well downtime and energy consumption at the same volume of production.
The strategy to develop this project started with the identification of well candidates where steam injection was not feasible then a change on the artificial lift system was proposed to a set of wells.
Also is highlighted the importance of the operational variables in long term at the moment to choose an artificial lift system.
The heavy oil reserves have increased more than twice as conventional reserves worldwide. Heavy oil has become in an important issued to the oil industry then and a concern to its best exploitation such technical as economical methods are considered.
Traditionally heavy oil exploitation considered Rod Pump (RP) as artificial lift system, exposing occasionally well downtime as sand stickings and rod failures with poorly designs.
Nowadays thankfully to the technological development an alternative for heavy oil exploitation is presented the Progressive Cavity Pump (PCP) which offers benefits as good heavy oil and high sand contents handling and low initial investment and maintenance cost.
This paper exposes a study of the main technical and economical issues considered for the artificial lift system shift from RP into PCP in Teca and Nare fields located at the Middle Valley of Magdalena river Basin in Colombia.
Considerations for the shift system
Since its initial exploitaion (early 80`s) in Teca and Nare fields, Rod Pump (RD) was implemented together with cyclic steam injection as EOR to produce an oil of 12 °API and 12000 cp viscosity within heavy oil pattern.
On 1st of April of 2004 in Omimex Colombia (operator of the fields) a project of well description started and were identified a set of wells no suitables for steam injection due to conditions as high water cut, completion problems like collapsed casings, liner ruptures and high sand content at wellbore as well as low injectability factor.
A trial of PCP system on well Teca 326 started on 10th of January of 2005 with promising results on operational consitions and steady production of 50 BPD compared with the former RD.
Based on these results arose the idea to install 75 PCP systems on the set of wells with non injectable factibility.
According to the production rate 20 to 60 BPD (32 wells), 60 to 100 BPD (25 wells) and 100 to 150 BPD (18 wells) of the set of wells, three differents systems of PCP were designed with power of 10, 20 and 30 HP to cover respectively.
While installation of the new systems and period after an evaluation process and comparison, of performance and economics was done between the two systems. The results gives the following conclusions.
Technical issues evaluated were flow and viscosous fluid handling and specially energy consumption.
There are several kinds of injectivity decline models, going from phenomenologicals ones, that consider the suspended solid mass balance and its damage on well and reservoir, through empirical models based on the experience with a previous field or even historical data. This article presents an evaluation of three differents models:
In this work, we compare results from these models and adjust them to fit historical data from injectors wells. Using literature date, we have also estimate parameters from all models and use them to predict the same well behaviour.
Injectivity decline (ID) is a constant problem to reservoir engineer. Water quality specification, workover frequency and well geometry are always being optimized by engineers trying to get an optimal well performance.
A way to do this optimization is the use of an injectivity decline model and check how the ID changes when injection conditions like solid content or well open section area are adjusted. Those kinds of models are available commercially (built in flow or well simulators) or even just reported at the literature. The objective of this work is compare some ID models, using a historical data from an injector previuously reported as a reference. Initially, we will introduce the models, theirs parameters and how to estimate them. Later we will
compare all results and try to fit the historical data.
Injectivity Decline - Phenomenological Model
The flow of solid-containing suspensions have been studied in many engineering branches, including the petroleum one, and was widely reported in the literature, including papers published on the impact of formation damage resulting from water injection.1-2
The basic mathematical model for deep filtration with particle retention consists on the mass balance equation and the kinetic equation for clogging. The phenomenological model (PM) used in this work consider the equations and analytical solution as proposed by Bedrikovetsky et alli3.
The emulsion (water, crude and solids) remaining in W/O interface after dehydration (water removal) constitutes Slop crude. Its recovery requires more complex processes than conventional treatment of crude because it has a very stable emulsion and vast amounts of fines. In the oil industry filtration is commonly used to treat crudes with such characteristics.
Shear effect, resulting from filtration of a Slop crude from west Venezuela, on emulsion stability and thereby on its dehydration was studied. Static stability tests, at laboratory scale, were conducted. They were carried out on diluted Slop crude, unfiltered and filtered with different meshes size, at different temperatures, injection of moisturizing and demulsifying products, and settling time.
After treatment, water and sediment content (%W&S) was lower in unfiltered crude than in the filtered one. All unfiltered samples reached commercial specifications (<1 %W&S). The parameter studied to explain how the filtration process affects emulsion stabilization was the determination of droplet size on the Slop crude, before and after filtration.
The microphotographs show that filtered samples have smaller droplet size than the unfiltered ones. Thus, evidencing that shear resulting from pressure drops and partial pluggings of meshes lead to decrease in emulsion droplet size and on increase stabilization. This decrease explains why thermochemical dehydration of unfiltered samples is more effective than that of filtered samples.
Based on these results, it was concluded that solid separation through filtration, prior to thermochemical treatment, is negative to dehydrate the studied Slop crude because a decrease of droplet size on the dispersed phase is produced, there by stabilizing emulsion even more.
Generally, oil is produced along with free and emulsified formation water, specially water in oil (W/O) emulsion and fines. The stability of these emulsions is caused by surfactants naturally present in the crude and produced fines1.
Crude, water and solids separation process, necessary to achieve less than 1 %W&S, is known as crude dehydration. During this process three different layers can be obtained: (1) the free water crude, (2) an intermediate layer (interface) made out of the emulsion between water, crude, and solids located in such interface, and (3) the water and solids separated at the bottom2. The intermediate layer is named interface crude or Slop crude and, generally, its recovery requires more complex processes than conventional crude treatment3.
The studied Slop crude is made out of the mixture of the dehydration process interfaces of different segregations treated in western Venezuela, one crude coming from the water clarification process and one crude that had remained in disposal for several years3.
It is important to emphasize that the crude Slop treatment is difficult not only because of the emulsified crudes from different segregations, with different characteristics and physicochemical properties, but because of the large time that this crude had been stored, without treatment, exposed to oxidation and polymerization processes, which had contributed to form a very stable emulsion between water in crude (W/O)1,3.
This study was carried out due to the great amount of Slop crude stocks and to the difficulty for its treatment, as well as to know filtration effect on the stabilization of W/O emulsion present on such crude and its influence in the treatment allowing dehydrating it and recovering the crude present in the emulsion3.
The conventional material balance methodology for fractured fields considers a single system with double porosity, compressibility, saturations, etc.
The method proposed in this paper employs a double reservoir concept.
This paper describes the use of neural network approach as a time series tool to represent the field as a black box, to make predictions of fluid production.
The classical tools available and widely used are numerical reservoir simulation and analytical methods, like decline analysis and material balance. These classical methods are not problem-free. Although the analytical methods are easy to use, sometimes they do not provide good results in several situations (changes of injection rates, opening or closing production intervals, etc.). On the other hand, numerical reservoir simulation, which usually gives better results, it is a very complex tool that may require several months to build a flow model of a field, especially when the field to be modeled is a mature field with several years of production history. Besides that, the flow models require an update from time to time, usually once a year, that also requires a lot specialized work for a long time.
Neural network techniques were applied in two sets of data from real fields to evaluate the possibilities of using this technology in this specific problem using only a small amount of production data as input for the predictive method. For that situation a short term prediction was performed. A synthetic reservoir was also used to generate a long production history in order to test how the technique would behave in a long term production forecast. For both cases, a comparison with classical methods is presented. Neural network architecture design and optimization techniques are also discussed. Results showed that the neural network models performed better than the decline curve analysis in all cases.
A tool that enables full field economic optimization, driven by gas and oil prices and costs of equipment operation such as compressor fuel gas, water disposal or electrical power generation has become a critical feature. An integrated model helps the production engineer to evaluate and design surface equipment where the behavior of the reservoir and wells are been considered at the same time. These mean that any change on pressure, volume or temperature on the surface conditions will affect the wells and reservoir behaviors and vice versa. If we project this to all the phases of the field life, from planning through development and operations, the need of an Integrated Model becomes more critical.
Common questions from reservoir engineers of what the impact would be of increasing choke diameters, changing artificial lift methods, decreasing separators pressures or installing compression could be answered with an integrated subsurface-surface model. On the same way, questions from operational engineers of what the impact would be of drilling new wells, stimulating the reservoir or implementing a secondary recovery could be answered with a model that looks at the behavior of the reservoir, well and facilities as an integrated system.
This paper proposes a work methodology and recomendations based on several projects carried out
throughout Latin America, especially in Petreleos de Mexico (PEMEX) and Petroleos de Venezuela (PDVSA).
Fluid behavior can be represented through a simple model using correlations to represent physical properties of the fluids (Black Oil), or a more sophisticated compositional model employing an equation of state (EOS) allowing to represent the components' behavior across the whole subsurface-surface system. What matters for both cases is that both the correlations for representing the physical properties and the equation of state must be tuned.
It is not uncommon to find a PVT set performed to different wells under different conditions. Though carrying out a quality control and reservoir fluid characterization needs some PVT skills, overlaying several physical properties on a graph is a good comparative indicator of PVT control. Figure 1 shows a graph with a quick check of the oil formation volume factor (Bo) vs. pressure for different PVT's.
It is important to mention that most PVT's made belong to the beginning of the reservoir's life, precisely to characterize that original fluid. This representative fluid from the beginning of the exploitation is of utmost importance for the engineer reservoir in order to be able to forecast its behavior on time on the reservoir (subsurface) level but not on the well or production facilities (surface); therefore we need to take into consideration that for most surface models we are trying to represent we employ a fluid that can be very different to the one being obtained today in the surface. It is recommendable to perform a current PVT or validate certain physical properties such as API gravity, viscosity, etc.