This work shows the main considerations adopted and proved successful for oilfield reactivation and production increase through the handling of very high gross production flow rate with high water/oil ratio. The execution strategy is focused on maximizing the production anticipation in the short-term by taking maximum advantage of the existing facilities and, in the mid- term, by developing facilities with new systems sized with flexibility and supplying them timely. All of these allowing to take advantage of the most suitable technologies existing in the market for handling, separation, treatment and disposition of high produced water flow rates, during the lifetime contract for each oilfield.
Examples of this approach are the study cases presented related to water injection for secondary recovery and disposal purposes. The knowledge obtained during the development and operation of a given mature field, has been adapted for its application in another field, and so on, considering particular features and different contractual terms, allowing PESA to success in very mature oilfields with apparently very restricted development opportunities.
The development and operation of mature oilfields in many cases demand handling high volumes of gross production, obsolete and under rated facilities that require huge investments, and tight returns making mandatory the optimization of operating expenses.
In order to plan and develop the surface facilities required to reach the objectives for reactivation and production increase in specific mature oilfields, main adopted considerations have been focused on three basic aspects:
The advantage of the obtained knowledge during the development and operation of mature fields, and the adaptation for extending its application to a different field, considering its particularities, including different contractual terms, allowed us to develop a high capacity in making fine adjustments to find opportunities in oilfields with high level of maturity.
Facilities Design. Criteria
The key factors applied in designing facilities in mature oilfields under revitalization are:
All of these factors are considered within the terms and duration of the specific operative contract for each oilfield, which is a real constraint in the planning of each development and a very important element for the project development analysis.
A significant common factor in these projects has been the decision to centralize the oil treatment in one facility, having satellites facilities for oil partial dehydration, from where the separated produced water is sent to water treatment plants. These plants are located in order to handle and pump the treated produced water into injection wells for secondary recovery or disposal purpose. (Fig. 2).
In hydraulic fracturing treatments, a fracture is initiated by rupturing the formation at high pressure by means of a fracturing fluid. Slurry, composed of propping material carrieby the fracturing fluid, is pumped into the induced fracture channel to prevent fracture closure when fluid pressure is released. Productivity improvement is mainly determined by the propped dimension of the fracture, which is controlled by proppant transport and proper proppant placement. Settling and convection (Density driven flow) are the controlling mechanisms of proppant placement. In this study, proppant transport and placement efficiency of four non-Newtonian fluids with controlled density differences was experimentally investigated and numerically simulated. Small glass model was used to simulate hydraulic fracture and parameters such as slurry volumetric injection rate, proppant concentration, and polymer type (rheological properties) were investigated.
It has been observed that small glass models easily and inexpensively simulated flow patterns in hydraulic fractures and the flow patterns observed are strikingly similar to those obtained by very large flow models used by previous investigators. Convection was observed to be significant flow mechanism even with small density contrast. As viscous to gravity ratio increases, due to increasing slurry injection rate or decreasing proppant concentration, convection settling decreases and proppant placement efficiency increases. Increasing non-Newtonian flow behaviour index (n) by using different types of polymers shows more gravity under-running and less proppant placement efficiency. Therefore, larger slurry volumes are needed to be injected in order to prop the entire fracture height. Experiments conducted were simulated and some of the simulated experiments were presented. The simulator quantitatively replicates the experimentally observed proppant placement and the match between the experimental and simulated results improves with the quality of fluids rheological data used in the simulation.
Bulk density gradient between the injected proppant carrying slurry and fracture pad fluid can cause strong gravity driven motion (convective settling), which in turn result in proppant misplacement at the bottom of a fracture. Cleary and Fonseca  indicated that convection is scaled to fracture width while settling is scaled to proppant diameter. The ratio of convective velocity to settling velocity may be of the order of 100 to 1000 even under ideal conditions and it may even be much larger due to the encapsulation effects or the suspension of solid particles in almost solid like viscoelastic gels. Clark and Courington  supported experimentally the findings of Cleary and Fonseca using a point source model and they indicated that convection is less important in thick viscous fluids. Clark and Zhu  expanded the range of density differences used in the previous work of Clark and Courington and concluded that more comprehensive studies are needed to understand the convection process. Barree and Conway  developed a computer model that yields evidence that convection is dominant under certain conditions of viscosity and fracture non-uniformity. Unwin and Hammond  presented and proved numerically that settling and convection can occur under field conditions and convection rates are slightly greater in sheet flow than in homogeneous flow. Mobbas and Hammond  numerically estimated the amount of convection during proppant placement. They indicated that convection and settling rates are greater in sheet flow than in homogeneous flow. Clark and Zhu  developed and validated experimentally dimensionless groups to predict the importance of convective flow. Both dimensionless groups are ratios of vertical to horizontal forces driving the flow. The non-Newtonian fluids viscous to gravity ratio was expressed as follows:
Recent studies have shown field data exhibiting a negative half slope trend in the pressure derivative that cannot be explained as spherical flow. In one case the well was located in an elongated fluvial reservoir bounded on one end by an aquifer acting as a constant pressure boundary. In another case the well was also in an elongated reservoir, this time crossed by a highly conductive fault. None has shown a rigorous derivation for the analytical equations for this flow regime.
This study derives flow regime equations for two new flow regimes encountered by a well near a constant pressure boundary. When there is no evidence of another nearby boundary, the pressure derivative trends are radial flow until the constant pressure boundary is encountered, and after that a straight trend with negative unit slope is observed. This flow regime is named here as dipolar flow. When the well is in an elongated reservoir near a constant pressure boundary perpendicular to the elongated direction, possible flow regimes include radial, dipolar flow, linear flow, and a flow regime with negative half slope, which is named here as dipole linear flow.
Normally falling derivative behavior due to a constant pressure boundary is assumed to signal the end of any useful parameter estimation, but the new dipole flow regimes are sensitive to permeability and to the distances to the constant pressure boundary and to boundaries defining the elongated reservoir. This study shows how to use the flow regimes to determine distances to closed and constant pressure boundaries, and to identify bedding plane permeability anisotropy (kx from well to constant pressure boundary, ky parallel to constant pressure boundary plane). The new flow regimes are present in standard single fault and rectangle models for pressure transient behavior, but they have never been rigorously derived or described.
The plot of the log of the pressure change and its derivative with respect to superposition time as a function of the log of elapsed time was first introduced by Bourdet et al.1 as an aid to type-curve matching. Referring to the Bourdet plot as the log-log diagnostic plot, Ehlig-Economides2,3 summarized relationships between pressure derivative responses and flow geometries described as "flow regimes??. In the past 20 years, flow regime analysis has been accepted by industry and used widely in commercial interpretation software.
A commonly encountered flow regime, a negative half slope trend in the derivative is known as an indication of spherical or hemispherical flow. Ehlig-Economides et al.4 studied in detail this flow regime, which is associated with the limited entry completion.
However, some field data exhibit a negative half slope in the pressure derivative but cannot be interpreted as spherical or hemispherical flow. Two cases can be found in literature. One case is given by Escobar,5 who studied an elongated reservoir with a constant pressure boundary normal to the elongation. However, the author mistakenly named the negative half sloping flow regime parabolic flow because he observed a parabolic shape for the isobars created by a numerical simulator. In this work, we will show the correct model does not give parabolically shaped isobars. The other case was presented by Al-Ghamdi et al.6 This time a highly conductive fault serves as the constant pressure boundary in an elongated reservoir. This paper showed field examples illustrating the same negative 1/2 slope trend and provided a model to match the data, but it did not provide a flow regime equation for the behavior.
In both cases the well was located in an elongated reservoir which is bounded on one end by a constant pressure boundary. The schematic plan view is given in Fig. 1. Here the term "elongated reservoir?? means a long, narrow reservoir which could have a stratigraphic origin such as fluvial deposition, or a structural origin such as parallel sealing faults.5, 7-9
In addition, unlike the rapid drop in the pressure derivative seen when a well is surrounded by a circular or square constant pressure boundary, when the well is near a single lateral linear constant pressure boundary, the pressure derivative drops with a slope of -1. Physical examples of such a constant pressure boundary include a downdip aquifer10 or an updip gas cap, or a well near a finite conductivity fault.11 A diagram of a well near a single constant pressure boundary is shown in Fig. 2. This figure also illustrates that a well near a constant pressure boundary is equivalent to the well plus an image well with a rate of opposite sign at a distance twice that between the well and the constant pressure boundary.
Marcos D., Jose (Sincor Inc.) | Pardo, Erika Mariana (Sincor Inc.) | Casas, Jhonny (Sincor Inc.) | Delgado, Denys Gaberial (Sincor Inc.) | Rondon, Maria Alejandra (Sincor Inc.) | Exposito, Miguel A. (Sincor Inc.) | Zerpa, Lemnis B. (Total S.A.) | Ichbia, Jean-Marc (Total E&P) | Bellorini, Jean-Paul
Sincor is a strategic association between PDVSA, Total and Statoil, committed to the production, upgrading and commercialization of extra heavy oil from an area covering over 325 Km2 in the Orinoco Belt (Figure 1).
The Sincor area is composed of a series of stacked unconsolidated sand-shale reservoirs with good petrophysical properties. The depositional system can be divided in two main parts, Deltaic and Fluvial. Fluvial sands, mainly stacked braided channels, represent the bottom part of the reservoir. Deltaic sands go from distributary channel and mouth bar to point bar and crevasse splay.
Drilling of vertical observation wells and a testing campaign started at the end of 1999. In well tests, anomalies in water
salinity values were observed: an aquifer salinity of 2300 ppm, while some wells produced water at 15000 ppm. At
that time, high values were considered measurement problems.
In 2001, the first horizontal producers started to cut water with similar high values to those observed in some well tests. Since then a multidisciplinary study was launched aiming at defining and characterizing all water sources using well tests (15 vertical wells) and water production data (150 horizontal wells). This information has then been integrated
with geological interpretation and reservoir characterization. In this paper a static model is developed using well test
information from the area. The model explains why different ranges of water salinities were observed in the oil and water
zones. This model was corroborated qualitatively with log information.
Dynamic data confirmed and detailed further the initial model. An exponential decrease of water salinity is generally observed with increasing water production or water cut. This phenomenon is explained by probable water influx in the form of fingering from the low salinity aquifer continously displacing high salinity formation water. The exponential curve shape would depend on the tortuosity and length of the path between the water and the produced oil zones.
Static and dynamic data are consistent and confirm our model of water production mechanism observed in the field.
SINCOR is a joint venture company between PDVSA (Petroleos de Venezuela SA), Total and Statoil. It aims at the cold production of 200,000 bbl/d of 8.5 °API extraheavy oil and at upgrading its quality to 30-32 °API in its refinery. The field is located in the south of Anzuategui state, Venezuela and the refinery is to the north. The oil is transported via 200 Km of pipeline (Figure 1).
The area of Sincor has been divided in cluster areas of 3.2 Km x 1.6 Km. In the middle of each cluster a vertical well is
drilled and used as an observation well to obtain geological and petrophysical data. Well tests are occasionally performed and monitoring devices are installed in these wells. Horizontal producers of 1400m are then drilled from
the center of each cluster. In eight years, more than 400 horizontal wells have been drilled.
After one year of production, some horizontal wells started to cut water. The rate of increase of their water cut was
different depending on the area and the stratigraphic level from which the wells produced. Together with these variable
water production behaviors, anomalies in some water salinities (higher values) were also observed. Initially these
anomalies were interpreted as measurement problems. During more than 3 years, the multidisciplinary team created
to study these anomalies gradually improved its understanding of the water behavior and eventually reached some interesting conclusions critical for future decisions concerning production policy and reserve evaluations. This
paper presents the result of the study.
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.
Reaching dew-point conditions upon depletion in a near-critical gas reservoir results in the precipitation of a liquid hydrocarbon phase or condensate dropout. Condensate dropout is usually immobile and impairs the flow of the other phases, adversely affecting reservoir productivity and ultimate recovery in this type of gas reservoirs. In the case of fissured reservoirs, the high-conductivity channels supplied by the fracture network will be prone to faster depletion upon fluid withdrawal. Condensate dropout would then occur in the fracture network first and then in the external edges of the matrix blocks. Even though condensate dropout in the fracture may have considerable mobility, this is not the case for the liquid formed at the external portions of the matrix. In this scenario, liquid buildup will hinder the flow of hydrocarbons from the inner portions of the matrix blocks and severely obstruct their recovery. This study aims at the numerical tracking of the liquid barrier, which requires a fine discretization of the inner portions of the matrix blocks, and the analysis of the interplay between the condensate barrier and hydrocarbon flow within the surrounding matrix/fracture system. While traditional wisdom dictates that reservoir condensate dropout is undesirable because this valuable condensate may be completely lost to the formation, this study analyzes if the situation is even worse for the case of fissured systems. In addition to low surface condensate recoveries, condensate appearance in fissured systems may also indicate that the inner-block gas stored in the matrices—where the bulk of the reservoir storage resides—might be also unrecoverable. In this study, guidelines for the development of this class of reservoirs are presented by identifying the controlling parameters of system behavior and ultimate recovery and analyzing the depletion characteristics of near critical fluids in fissured systems.
This paper describes a new Downhole Fluid Analysis technology (DFA) being implemented in Latin America for improved reservoir management. DFA is a unique process in fluid characterization for improving fluid sampling, reservoir compartmentalization evaluation and support flow assurance analysis. It combines known and new
fluid identification sensors, which allow real time monitoring of a wide range of parameters as GOR, fluorescence, apparent density, fluid composition (CH4, C2, C3-C5, C6+, CO2), free gas and liquid phases detection, saturation pressure, as well WBM & OBM filtrate differentiation and pH, which is key for real time contamination monitoring at the well site with the objective of representative sampling and reservoir compartmentalization analysis. This
process is not limited to light fluid evaluation or sandstones.
The combination of DFA Fluid Mapping with pressure measurements has shown to be very effective for compartmentalization characterization. The ability of thin barriers to hold off large depletion pressures has been established, as the gradual variation of hydrocarbon quality in biodegraded oils. In addition, heavy oils can show large compositional variation due to variations in source rock charging but without fluid mixing .
Using this method we present field DFA data acquisitions and integrate into numerical simulation modeling to conceptually evaluate the impact of fluid composition / properties gradation and compartmentalization in the productivity of some Latin America reservoirs.
Exploration wells provide a narrow window of opportunity for collecting hydrocarbon samples to make development decisions; therefore, obtaining high-quality samples and performing an adequate fluid scanning along the hydrocarbon column is imperative whether the prospect is in deep water or on the continental shelf. That is, one can obtain a
continuous downhole fluid log. This log records (vertical) composition variation along with some indications of compartments or connectivity. Testing well production is a common way to obtain fluid samples, but usually does not allow a detailed areal or vertical fluid scanning for compartmentalization, gradual variation of hydrocarbon quality or density inversion analysis, and is not always feasible for economic or environmental reasons. Downhole samples define fluid properties that are used throughout field development.
Downhole Fluid Analysis technology (DFA) is a concept, rather than a specific tool. Currently, DFA relies on near-infrared spectroscopy (NIR) and new novel approaches. The details of NIR application for DFA have been described elsewhere [2, 3].
The challenge of the alpha/beta waves gravel packing open hole in offshore Brazil is how to successfully displace the proppant slurry in a large wellbore with a low fracture gradient formation, deep to ultra-deep water depths, and extended reach horizontal section.
Since 2001, job data from more than 72 open hole horizontal gravel packings have been compiled into a database. This paper reviews the well information and the key gravel packing parameters: pump rate, fluid density, injection proppant concentration, inner/outer annulus area ratio, dune ratio, packing rate, packing time and packing efficiency during alpha/beta waves. The engineering implementations and challenges, the best practices and lessons learned for open hole horizontal gravel packing are also summarized. The data analysis yields a better understanding about the open hole horizontal gravel packing in the Brazil offshore and provides a good guideline for future practice. A historical review is also presented showing how the gravel packing methodology has improved packing efficiency and success rate.
Case histories are provided demonstrating how to deploy the single trip system and pack the extended reach wellbore utilizing ultra-light-weight (ULW) proppant under extreme with improved packing efficiency and the success rate.
Deepwater exploration and production has developed over the last decade. There is a broadening of the geographic regions for deepwater completions (figure 1). The vast majority of the deepwater reserves are concentrated in the Gulf of Mexico, West Africa, Brazil, North Sea and South East Asia. The potential to achieve significantly higher sustainable production rates, well longevity and cost reduction have been the primary drivers for pursuing most deepwater completions. There have been many different types of completions in deepwater, however, the frac-packs and open hole horizontal completions have emerged as the two dominant completions. Appropriate applications are area dependent. In Brazil, the dominant completion type is the open hole horizontal gravel packing. In the Gulf of Mexico, 60% to 70% of completions are frac-packs. In West Africa both open hole completions and frac-packs are used.
Based on published references 3 to 19, open hole horizontal gravel packing envelops, in terms of depth and the hole departure, are plotted in figures 2 and 3. The latest world record horizontal gravel pack was completed in a well with the departure length of 4206m and a departure ratio of 5 in the Captain Field in the North Sea.13 The open hole horizontal gravel packing completed in the deepest well was in the Campos Basin field of Brazil with sub-sea TMD of 5093m and TVD 3855m.
Typical reservoirs in Campos Basin fields are high permeability turbidite sandstones with low API gravity oil. Generally, these unconsolidated formations are not strongly water driven. A high rate injection was needed to maintain reservoir pressure on these large producers. Several fields in the Campos Basin were developed with a series of horizontal producers and injectors.
More than 200 open hole horizontal gravel packings have been completed since 1998 in Brail1,2. Current gravel packing technology offers a good option for horizontal well completions where the problem is sand production.
Key issues in project planning and execution of open hole horizontal gravel packing include reservoir study, shale stability study, formation integrity test, gravel pack sand sizing, gravel pack screen selection, workstring design, well displacement, and fluid loss control. The feasibility and success of gravel packing a long horizontal well depends on drilling techniques, drill-in fluids, wellbore clean-up, completions fluids, completion tools, equipment, sand control techniques, software/simulators, pumping schedules and field personnel experience.
Challenges that can jeopardize performance of successful open hole horizontal gravel packing are excessive fluid loss, varying hole geometry that can lead to premature pack termination, hole stability issues leading to hole collapse, and a narrow pressure window between bottomhole pressure and fracture gradient. The beta-wave placement pressure is the main factor in determining the maximum length of a horizontal gravel pack. This pressure is limited by the requirement to install the gravel pack without exceeding formation fraction pressure.
Successful design and implementation of a miscible gas injection project depends upon the minimum miscibility pressure (MMP) and other factors such as reservoir and fluid characterization. The experimental methods available for determining MMP are both costly and time consuming. Therefore, the use of correlations that prove to be reliable for a wide range of fluid types would likely be considered acceptable for preliminary screening studies. This work includes a comparative evaluation of MMP correlations and thermodynamic models using an equation of state by PVTsim1 software. We observed that none of the evaluated MMP correlations studied in this investigation is sufficiently reliable. EOS-based analytical methods seemed to be more conservative in predicting MMP values.
Following an acceptable estimate of MMP, several compositional simulation runs were conducted to determine the sensitivity of the oil recovery to variations in injection pressure (at pressures above, equal to and below the estimated MMP), stratification and mobility ratio parameters in miscible and immiscible gas injection projects. Simulation results indicated that injection pressure was a key parameter that affects oil recovery to a high degree. MMP determined to be the optimum injection pressure. Stratification and mobility ratio could also affect the recovery efficiency of the reservoir in a variety of ways.
Through the past decades, miscible displacement processes have been developed as a successful oil recovery method in many reservoirs. The successful design and implementation of a gas injection project depends on the favorable fluid and rock properties. The case studies using Eclipse2 compositional simulator considered the effect of key parameters, such as injection pressure, stratification and mobility ratio on the performance recovery in miscible and immiscible flooding of the reservoir. However, accurate estimation of the minimum miscibility pressure is important in conducting numerous simulation runs. MMP is the minimum miscibility pressure which defines whether the displacement mechanism in the reservoir is miscible or immiscible.
Thermodynamic models using an equation of state and appropriate MMP correlations were used in determining the MMP.
Compositional simulation runs determined the sensitivity of the oil recovery to the variations in above mentioned parameters. Significant increase in oil recovery was observed when interfacial tension dependent relative permeability curves were used. These relative permeability curves provide an additional accounting for miscibility by using a weighted average between fully miscible and immiscible relative permeability curves. The local interfacial tension determines the interpolation factor which is used in obtaining a weighted average of immiscible and miscible (straight line) relative permeabilities.
Simulation runs were performed at pressures below, equal to, and greater than estimated MMP for reservoir fluid/ injection gas system. Oil recovery was greatest when miscibility achieved.
To investigate the effect of stratification on the performance recovery of the reservoir, the base relative permeability of two layers changed. Location of the high permeable layer (up or bottom layer) in the stratified reservoir greatly influenced the efficiency of the reservoir.
Understanding the effect of interfacial tension and adverse mobility ratio on the efficiency of the gas injection project was the last case study. Injection gas and reservoir fluid compositions differed in such a way to have interfacial tension and mobility dominated mechanism. To investigate the effect of interfacial tension water was considered as a fluid with much higher surface tension values with the oil. Lower surface tension values between rich gas and reservoir fluid (interfacial tension dominated) made gas injection project a more competitive recovery method than waterflooding. In mobility dominated displacement mechanism (lean gas/reservoir fluid system) the viscous instabilities were more important than the interfacial tension effect. For this case, waterflooding with favorable mobility ratio resulted in higher oil recoveries.