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.
Guerra, Edilena (Intevep S.A.) | Valero, Emil Margarita (PDVSA Intevep) | Rodriquez, Daniela (Petroleos de Venezuela S.A.) | Gutierrez, Luz (Petroleos de Venezuela S.A.) | Castillo, Maria (Petroleos de Venezuela S.A.) | Espinoza, Javier (Espol) | Granja, Gustavo (Petroleos de Venezuela S.A.)
In design and implementation of Alkali Surfactant Polymer (ASP) formulation for IOR processes, the inorganic alkali component acts as sacrificing agent avoiding the surfactant adsorption and decreasing the IFT. Nevertheless, as a part of this process there are some potential problems to be considered previously and during ASP injection processes such as: the ASP injection water should be softened to prevent scale formation that produces higher costs for water treatment, possible tubing corrosion problems and possible viscosity reduction. The effect of organic alkali on IFT, adsorption and viscosity has been previously focussed on comparing to the conventional inorganic alkali in these formulations. In those investigations, it was founded that organic alkalis are compatible with unsoftened waters and the rest of ASP slug components, reduce adsorption, minimize the surface equipment and the formation damage what reduces initial investment costs and greater project profitability.
The objective of this study is to show the advantages and outcomes in applying an improved design of the current ASP formulation for the pilot project La Salina Field Maracaibo Lake, using an organic compound-surfactant-polymer (OCSP) formulation, which uses an organic compound as substitute for traditional inorganic alkali. In fact, fluid-fluid and rock-fluid compatibility laboratory tests, new chemical components concentrations, phase behavior study, IFT screening and porous media evaluations (adsorption and recovery factors) were performed in laboratory in berea cores. Linear corefloods displacements for La Salina LL-03 let to obtain the OCSP flood recovery and additional OOIP estimated of 22.2%. Finally, these results confirm the technical advantages of applying an optimized formulation using an organic agent for this field.
The ASP technology is an enhanced oil recovery method which combines the synergetic effects of three components (alkali, surfactant and polymer) in order to improve the sweep efficiency to oil residual saturation. This effect is achieved with the reduction of the IFT from the injection of surfactants and alkaline solutions which also acts like sacrificing agent to diminish the adsorption of surfactant and polymer into the porous media. The polymer injection lets to increase the viscosity of ASP slug, which is fundamental to improve the volumetric sweep efficiency.
There are numerous successful international experiences in the ASP technology application. Particularly, those in US and China fields represent the most emblematic experiences 1, 2, 3. La Salina Field, on the eastern coast of Maracaibo Lake in Venezuela, is ASP pilot project designated contemplating all different and crucial stages of this process: development of the corresponding optimal ASP formulation for LL-03/Phase III reservoir, numerical simulation model and design of an injection plant 4.
An estimate of 19.0% was considered as the incremental recovery factor for reservoirs of Miocene with the injection of ASP according to previous studies to optimal ASP formulation. The area of Phase III has been subject to water injection project since 1987. The injection has been carried on by inverted seven spot well patterns. The ASP injection project contemplates to implant the technology in three arrangements initially. The subject tests development in this study corresponds to the first arrangement, where is located the well PB-734. The type of arrangement is a triangular form with a separation between wells of 150 mts aproximately. In the center of the triangle, a well injector of ASP and one observer are located. All these wells were completed with sensors of pressure and temperature of bottom. Figure 1 shows the area of study into the Phase III and the Table 1 lists the reservoir typical characteristics of the LL-03, La Salina.
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 Beta distribution in n-dimensions is introduced to describe the proportions of the mineralogical components existing in a certain stratigraphic interval (the porosity is included as a "mineralogical component??). The justification for doing so is empirical. The model allows the calculation of well logging parameters, such as GRma, GRsh, shale density, etc., without having to introduce them by "eye??. It also allows the probabilistic calculation of the rock composition at each depth when there are more mineralogical components than logs: that is, there is a shortage of equations. In addition to this, the Beta model can be used to test the hypothesis that the relationship between any two components can be regarded as random, which should have applications in reservoir characterization.
A new mimetic method for solving tracer flow equations in oil reservoirs is presented. This mimetic method is a formal extension and an improved version of standard finite differences schemes and it has three main advantages. First, its grid is a hybrid version of point center and point distributed grids, so the new method does not require ghost points in its formulation and implementation. Second, boundary conditions approximations achieves same order of convergence as inner nodes, it is well known that standard finite difference schemes convergence rate deteriorates at boundaries. Third, the new scheme satisfies Green-Gauss-Stokes identity at the discrete level, which guarantee that the scheme is fully conservative and represents correctly the physics properties of the problem. The new scheme was implemented to solve tracer flow equations in a reservoir and it was tested in a set of five spot problems. Numerical results show that the new scheme produces better approximations than standard finite difference simulators on coarse grids.
Mimetic methods are a new kind of numerical method for solving partial differential equations. They have been developed in the last ten years. It was originated in the Soviet Union by academician A.A. Samarskii and further developed in western countries in the late nineties[1, 2, 3]. It should be said that denomination of mimetic has been coined only recently. Mimetic methods are also called support operators or conservative methods from its earlier years. The main idea of this method is to produce discretizations of fundamental differential operators such as gradient, divergence, and curl in terms of which the differential equations of the mathematical physical problems of interest are written. These discretizations must satisfy or mimic discrete versions of the integral identities valid for the fundamental differential operators at the continuous level. In particular, it is said that a numerical scheme is mimetic if its discretization of the fundamental operators satisfy a discrete version of the Green-Gauss-Stokes identity, although there is not a general agreement on this definition. Mimetic schemes have many advantages: they are conservative, their discretization formulas are finite differences molecules, linear systems associated to them are banded and sparse, their formulation distinguishes between the differential equations and its boundary conditions at discrete levels, they do not use ghost points, and they can be used on irregular grids. It could be said that mimetic methods are an improved version of finite differences methods that provides an alternative choice to finite element methods in the case of fluid flow problems. Second order mimetic schemes have been developed since mimetic method's earlier years, a full account of them can be found in the literature[1, 2, 3] and their only application to petroleum engineering, up to year 2006. However, these second order versions have the limitation that their discretizations at the boundary produce lower orders of convergence than in the interior points. Recently, a new mimetic scheme which achieves same order of convergence in all grid nodes has been developed. The second order version of this new mimetic scheme was studied[7, 8, 9] and its application to reservoir simulation has not been reported.
This article presents an adaptation of the fully second order mimetic scheme developed[7, 8, 9] for solving tracer flow equations in an oil reservoir. Numerical simulation of tracer flow in porous media is the simplest type of fluid flow problem in petroleum engineering and groundwater modeling. It provides the best model to test a new numerical scheme. Consequently, its formulation, test problem, and numerical results represent a new contribution to the technical literature.
The rest of this paper is distributed in four sections: First section describes tracer flow equations with their boundary conditions. Second section formulates the new mimetic scheme for solving tracer flow equations. Third section provides tests problems and numerical results. Finally, the fourth section shows the conclusion and recommendations.
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.
The analysis of alternatives of development of gas deposits and condensed is usually carried out by using the coupling between the balance of materials in predictive mode and the nodal analysis or also using numerical simulation models. In both cases it is required a suitable model of the multiphase flow behavior in vertical pipes in order to be able to predict with accuracy the flowrates the wells will produce through the different life stages of the reservoir.
The correlations for the multiphase flow, with which it is modeled the flow in vertical tubes, show a big dispersion of results in flowrates less than 50 km3std/d with gas - liquid relationships less than 10000 m3/m3. This area of low flowrates and low gas - liquid relationships is usually observed in the gas and condensed reservoirs final phase due to the decline in the production because of the fall of the static pressure and the fall of the gas - liquid relationship and the increase of the water cut.
Consequently, the dispersion in the correlations generates important differences in the production forecasts, with the associated high economic impact, because the pressures for abandonment of the wells are very different according to the multiphase correlation used.
In this work we show an exhaustive statistical analysis of the behavior of the multiphase flow correlations in vertical tubes, contrasted with measurements of pressure gradients in wells, in the majority of the cases within the ranges of flowrates and gas - liquid relationships mentioned in the previous paragraph.
From the results of this analysis, it is developed a new correlation of multiphase flow for gas - condensed - water systems that allows predicting the pressure gradients in vertical tubes within the reasonable error ranges.
We show the methodology used for the development of the correlation and the statistical analysis of the results of the application of it based on the data from the studied cases.
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.