Original Oil In Place (OOIP) calculations based on material balance methods are strongly influenced by data uncertainty. Although some research is available in literature, usually the effects of data uncertainty on material balance calculations are rarely considered and quantified in most studies. This work presents an approach to properly quantify and account for the impact of reservoir pressure and PVT data uncertainty on material balance calculations under different drive mechanisms and using different material balance methods. This study allows reservoir engineers properly select the most suitable material balance method when uncertainty on reservoir pressure and PVT data is significant.
In this work, two different methodologies are proposed. First, a sensitivity analysis was conducted using generated realizations of reservoir pressure and PVT data to evaluate their effect on material balance calculations. Second, a more robust approach was proposed using experimental design and analysis of variance to systematically evaluate the influence of reservoir pressure and PVT data on material balance calculations in an optimal and integrated fashion. In both methodologies, different material balance methods were used and computed OOIP were compared to reference values from a conceptual reservoir model with known PVT data and simulated reservoir pressure. A MATLAB-based program, with graphical user interface, was coded for this purpose1.
Application of the proposed methodologies allowed to determine and quantify the most significant parameters that influence material balance calculations. Interestingly, the most important parameter was the selected material balance method used to compute the OOIP. More accurate results were obtained using the traditional graphical method (F-We vs. Et) for volumetric oil reservoirs with minimal pressure and PVT data uncertainty. In those cases with moderate to significant water influx and gas cap, and some uncertainty on pressure and PVT data, less accurate original oil in place was obtained when graphical methods were used. Reservoir pressure uncertainty was the most significant parameter on the material balance calculations. Gas-oil ratio uncertainty was also significant. Oil and gas gravity, and reservoir temperature were less significant.
Material balance is a simple and one of the most important reservoir engineering tools. Calculations require production/pressure data, PVT data, and aquifer parameters, so that original oil in place and drive mechanisms can be quantified. Data quality is an important issue in material balance calculations. Uncertainty due to data errors can be found in field production data, measured PVT properties, and average reservoir pressure.
Usually, it is expected that oil and gas production are measured with confidence since industry revenues are based on oil and gas sales, and consequently error in production data can be considered minimal. However, reservoir pressure is uncertain since limited well measurements are usually available and averaging procedures might introduce some uncertainty in the computed reservoir pressure history. PVT data can be also uncertain since some reservoirs have no representative fluid samples for a complete PVT analysis and correlations are used instead for material balance calculations.
Frac-pack is a pervasively used completion technique in wells targeting high permeability, poorly consolidated and depleted sandstone formations located in Bachaquero, Tía Juana and Lagunillas fields in West Venezuela. This technique combines stimulation and sand production control in a single treatment by placing a short and wide fracture which bypasses the near-wellbore damage, while gravel-packing the zone of interest.
This paper describes a novel and economical frac-and-pack technique which consists of pumping a sand plug with the downhole tool set for circulation to isolate a bottom set of perforations, followed by conventional frac-and-pack. When this procedure is followed, the fracture is forced to propagate along the upper intervals. This novel technique is particularly useful for wells with water-producing zones near the bottom of the target zone, because it induces selective growth of the fracture along the upper intervals and mitigates the risk of growing the fracture into the water-producing zone.
A case study of a frac-and-pack performed in a Lagunillas field well with a water contact 40 ft below the target zone is reviewed. The intervention rendered an increase in well production rate from 27 to 173 net barrels per day with a reduction in water cut from 25% to 9%. In contrast, two wells in the same field and with very similar characteristics which were frac-and-packed conventionally rendered 100% and 63% water cuts, respectively.
Another application of this technique refers to frac-and-pack of wells with long perforated intervals where early wellbore screen-out may occur due to proppant bridging of the annular volume between the screen and the casing. Conventional frac-and-pack of twenty wells in these fields with perforated intervals exceeding 90 ft rendered a 40% early wellbore screen-out rate. The early wellbore screen-out rate was reduced to 12% in a sample of twenty eight wells with the new technique. The average production rate increased from 2 to 135 BOPD, whereas the average estimated after-treatment production was 130 BOPD, for which this technique was considered successful. A shortcoming of the technique for this application is the fact that the bottom of the perforated interval is not fractured. High-end frac pack techniques that overcome this issue such as use of shunt tubes were found to render higher normalized oil production rates.
Carvalho da Silva, Augusto Cesar (Schlumberger) | Cavero, Jose Antonio (Schlumberger) | Rodriguez, Waldyr (Pluspetrol Peru Corp.) | Vargas, Johana (Pluspetrol Notre SA) | Augusto, Marco (Pluspetrol Peru Corp.) | Chacon Soplin, Rommel (Pluspetrol Peru Corp.) | Bardales, Alvaro (Pluspetrol Notre SA)
In the Sub-Andean basin areas of Peru, Colombia and Ecuador, important reservoir targets present very low resistivity range and also very low resistivity contrast between pay and non-pay. These unique conditions constitute a challenge in relation to the ability to map the reservoir boundaries and to allow the successful navigation of horizontal wells in thin target zones.
Conventional logging data are not able to effectively determine the approach or prevent the intersection of a reservoir limit under such reservoir conditions. Therefore, they are not perceived as the best option to optimize geosteering decision making.
A new logging while drilling technology, developed by Schlumberger, based on directional electromagnetic resistivity measurements was applied in a horizontal well, recently drilled by Pluspetrol Norte in Peru.
The service delivered directional resistivity measurement with deep depth of investigation, which allowed estimating the orientation, distance and resistivity of nearby bed boundaries. The technology was successfully used to navigate the well, optimizing the horizontal length inside the best productive zone and stay at a safe distance from the OWC. The productive behaviour of the well was better than expected.
Los Molles Formation in the Neuquén basin (Fig 1), west-central Argentina, contains a series of deep-water submarine channel complexes deposited in an elongate basin, during the Pliensbachian-Toarcian ages. These events developed during the final stages of the rifting phase. In the studied area, these submarine meandering canyons cut the shelf and gentle slope in a SSE-NNW direction, and represent the transfer zone of the system, where erosional features are more frequent and lithological distribution is more complex. The canyons are approximately 3 Km wide and several hundred meters thick and host a number of migrating channel-fill units inside, lying on erosional surfaces that cut into adjacent interchannel facies.
Applying neural network techniques in the three wells that penetrate this deep-marine strata, allowed the identification of five main lithofacies: muddy-matrix conglomerates, sandy-matrix conglomerates, coarse-grained sandstones, fine-grained sandstones and mudstones. Furthermore, the use of 3D seismic attributes was crucial to obtain the distribution of these facies within the canyons. For this purpose, techniques based on neural network and representative supervised "seed points?? next to each lithology around the well, were applied.
This work resulted in a seismic volume with the distribution of four seismic facies along the system in a very heterogeneous way. The fine grained facies clearly located in an overbank position; the sandstones and conglomerates show a distribution constrained inside the canyons, and is also easy to see how the net-to-gross relationship increases towards the distal positions of the system.
The techniques applied, greatly improve the success of prediction of potential reservoirs locations.
Exploring deep-water reservoirs is a challenging task, where an accurate characterization of the stratigraphy and facies distribution, happen to be the main target towards a robust geological facies model.
Los Molles Formation consists of a NNW-SSE elongate submarine system where a number of meandering canyons of strong erosional profiles cut into the shelf and slope, during Pliensbachian-Toarcian ages. Three main depositional provinces were detected: A proximal erosional zone, a channelized gentle slope with erosional and depositional features, and a downslope depositional channel mouth zone where the sandy fractions were pressumably deposited in a "collapsing?? way.
The discoveries of gas accumulations in nearby areas, triggered a detailed exploration of this unit and the need of understanding the facies distribution along the system. The development of models of deep-water systems for predictive exploration, has come to rely on all the available data like seismic, cores and logs.
Drilling operations for several operators in East Venezuela are increasing in complexity each year. Many challenges are encountered while drilling across weak formations with considerable variability in lithology and pore pressure. A narrow drilling window between formation pore and fracture pressures has become one of the main concerns for the operator. Primary cement placement faces similar challenges when placed across weak formations.
New producing zones are currently being targeted in deeper sandstone formations and a variety of loss circulation issues are encountered. For example, in the Tacata field, lost circulation is occurring across a series of depleted zones located above the producing zone. In the Orucual field, losses were observed immediately below the producing zone. From the wells observed in this study, losses were observed most frequently under slim-hole conditions and low fracture pressures. In these wells, combinations of demanding well and formation parameters have made it more difficult to achieve successful cement placement. Minimizing losses
during cement placement, achieving predicted top of cement (TOC) and reliable zonal isolation are current challenges in East Venezuelan fields.
The need to improve conventional lost circulation approaches during well drilling and cementing was determined by service company and operator field experience and dynamic cement placement simulations. A high performance light weight (HPLW) slurry was recommended along with an engineered fiber material (EFM) to avoid losses by reducing the hydrostatic pressure in the annulus and artificially increasing the fracture pressure of the thief zones during placement.
From several case histories, the synergy between HPLW and EFM approaches resulted in improved zonal isolation, less reservoir damage and cost savings by avoiding remedial cementing and non productive time (NPT).
The main Venezuelan oil fields are located in the northeast part of the country. Monagas state has the majority of the principal oilfields such as Oficina Major Area, Quiamare, Jusepín, El Furrial, Orocual, Boquerón, Tacata and Quiriquire. Some fields (e.g. Tacata) have more mature zones in shallow to intermediate depths that are reaching depletion and deeper producing sandstones are being targeted. Other fields (e.g. Orucual) possess thief zones immediately below the producing zone. Loss circulation is occurring across these depleted zones due to the narrow well security window. The well security window is defined as the operating range between the
pore pressure of the production zone and fracture pressure of the depleted zone.
Challenges and Problem Analysis
Operating outside the well security window incurs additional costs and unnecessary risks to personnel and equipment during well construction. Due to lost circulation in these fields, average NPT and mud losses exceed 48 hrs and 2,000 bbl, respectively, during the 17.5 in drilling phase for each well. These problems must be addressed by careful planning/design and risk analysis to reduce uncertainty to an acceptable level. For example, when losses are anticipated during drilling operations, careful drilling program design must consider several parameters, such as hole geometry, mud type/density, rate of penetration, surge and swab pressures, casing point selection, etc.
In narrow well security windows, casing point selection and cementing programs are also more complex with the added limitations of slim-hole conditions and increased friction pressures during cement placement. In order to reduce friction pressure, the operator may decide to reduce placement rates and increase the job duration. Reduced placement rates may contribute to increased risk for insufficient mud removal, incomplete zonal isolation and annular gas migration, which may require remedial squeeze cement methods to correct the problem. For example, several wells were tested under leakoff conditions following completion of intermediate and production strings using convention cement placement methods. General field observations by service company and operator personnel noted an increased leak-off failure rate. In strings that failed the leak-off test, at least one remedial shoe squeeze job was required to repair the problem. This added substantial cost to the operator in remedial cementing and NPT.
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].
CO2 injection is one of the most efficient methods used to improve oil recovery, and, as world statistics shows, its use has increased recently. Under a high crude oil price scenario, field applications of enhanced oil recovery (EOR) processes are becoming economic in today's environment. The natural CO2 sources come to be an excellent opportunity because of its low cost. Since 60 years ago, 2500 km2 of carbonate formations containing CO2 were discovered in North of Mexico.
The Quebrache region contains several occurrences of natural CO2 that have been discovered during exploration of oil fields. The CO2 that has been naturally trapped in carbonate formations in this region is present in concentrations that can exceed 90% purity. Due to the high concentrations of CO2, some wells were shut-in 60 years ago, others, have been developed for CO2 production intended for industrial uses and some others as a source of gas lift operations in nearby heavy oil fields.
Recently, a plan of acquisition of information and studies to evaluate the CO2 proven reserves has been designed. In addition, analysis of wells deliverability of these natural CO2 reservoirs, located in the southwestern portion of Tampico, has been carried out. In order to understand better this field, a geological model was built and its dynamic behavior and potential was examined through several well tests. Results of the interpretation of these tests showed excellent results associated with a reservoir of good permeability, high conductivity, large drainage radius, etc. According to the geology of this region and the geochemical signatures observed, the CO2 of Quebrache field has an inorganic origin.
This paper discusses the evaluation of potential supply of CO2 of Quebrache reservoirs for EOR projects in the North of Mexico. The main region studied contains estimated proven reserves of 1.9 Tscf of CO2; however, this volume could be extended to larger amounts associated to areas under study. The CO2 from Quebrache field could be the beginning of a new era of EOR projects in Mexico. A field example of potential EOR application in a mature oil field is shown.
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.
In this paper, we will describe techniques used to overcome the problems faced on the hydraulic fracturing jobs during the oil-to-gas conversion campaign in the Pilar field, Brazil.
The increasing demand for clean-burning natural gas in the Northeast of Brazil is fueled by the region`s industrial growth over the recent years, and represents the main drive for the oil-to-gas conversion campaign witnessed in the wells previously producing at marginal oil rates from the Coqueiro Seco formation in the Pilar field. These old wells are now producing gas from the 3000 meters deep Penedo sandstone formations. One of the main steps to meet the goals for natural gas output in the Pilar field was the hydraulic fracturing campaign in the deep Penedo formation. The treatment design and execution process to create these fractures was quite distinct from the normal jobs aiming at increasing the oil productivity in wells producing from the shallow Coqueiro Seco formation.
The Barra de Itiúba gas-bearing formation in the Furado, São Miguel dos Campos and Cidade de São Miguel dos Campos fields was also included, to a lesser extent, in the stimulation campaign aiming at the increase in natural gas production.
This paper describes the completion strategy for the old wells converted from oil to gas producers, highlighting the problems faced and overcome during the hydraulic fracturing campaign. In deviated wells crossing the deep Penedo reservoir, the risk of multiple fractures and influence of tortuosity have been diminished through corrective techniques, unique for each one of the existing wells. In the early hydraulic fracture treatments performed in the Pilar field, premature screen-outs were commonplace, disencouraging the use of the technique. The need to produce gas brought new ideas to the battlefield, and their implementation led to results beyond expectations.
The intense investiment to increase production of natural gas in the Alagoas, and its export through an expansion of the domestic natural gas transport network in the Northeast of Brazil, has the objective to keep up with the rapid growth in the regional gas consumption, due to an increase in the natural gas fired electricity generating capacity. Natural gas demand in Brazil, 1600 million scf/day in 2006, is expected to reach 4300 million scf/day by 2010, the direct result of investments in the sector estimated in US$ 22 billion.
The natural gas processing plant in Pilar was built to develop the compressed natural gas market for automotive, residential and commercial use in Alagoas, and to export gas through the Pilar-Cabo pipeline. Before its construction, all natural gas produced in Pilar and its neighboring fields was exported for processing and pumped back in the form of liquified petroleum gas. Seventy million scf/day of natural gas are processed in the Pilar plant, producing liquified petroleum gas, industrial gas and gasoline.
Given the increased demand for natural gas in the region, the gas-bearing formations in the Pilar area became attractive targets. Hydraulic fracturing played a major role in converting old oil wells producing at marginal rates from the shallow Coqueiro Seco reservoirs into good gas producers.
The Pilar Field
The Pilar, São Miguel dos Campos, Cidade de São Miguel dos Campos and Furado onshore gas and oil fields are located in the state of Alagoas, in the Sergipe-Alagoas Basin, in the Northeast of Brazil (Figure 1).
The Pilar field, discovered in 1981, is located near the city of Pilar (Figure 2). The Pilar field is characterized by intense compartmentalization produced by deltaic sedimentation that resulted in a stacked package of more than one hundred pay intervals, and by the extensional tectonics that produced a large number of fault blocks (Figure 3). The deposition occurred during the rift phase of the geologic evolution of the Sergipe-Alagoas Basin, in the Lower Cretaceous.
Intercalations of deltaic sandstones and shales compose the Coqueiro Seco formation, found at depths ranging from 500 to 2500 meters. These oil-producing sandstones have porosity of 20% and permeability of 100 mD.
In order to improve the seismic imaging and delineation of a reservoir, an OVSP was run in an exploratory well; Neuquén Basin; Argentina. A second purpose of this acquisition was to accurately locate an Intermediate Casing above the main target. Acoustic Impedance Inversion of the corresponding Zero Offset VSP plus the image interpretation generated from the OVSP data helped to define the position of a sill, which was one of the objectives in this project.
The thick (hundreds of meters) and extensive Auca Mahuida volcanic complex which covers most of the region, considerably reduces the signal to noise ratio of the seismic data; strongly attenuating the high frequencies of the data due to wavefields dispersion, hampering their separation at the processing stage. This effect is stronger in surface seismic than in borehole seismic, due to greater offset and two-way traveltime, so that VSP is used as a tool in this environment. Therefore, Q factor estimation (and consequently Q inverse filtering application) computed directly from Zero offset VSP, is a very valuable technique which allowed us to recover high
frequencies in the field area improving vertical seismic resolution and helped to define the reservoir with greater accuracy.
An acoustic impedance inversion of the VSP trace was later obtained, and its interpretation was very useful to predict impedance variations, related to lithology and formation changes in the deeper portion of the stratigraphic column. This was the first deep exploratory well (4750 meters) in this part of the basin, so the implemented technique led to define deep formation tops.
The acquisition was performed by Schlumberger using the multilevel 3C high-fidelity downhole tool, Versatile Seismic Imager (VSI). It was used two vibrators simultaneously in flipflop configuration for both source positions in order to reduce the operational time.
In this paper we describe the objectives, methodology and results of a Borehole Seismic Job performed in an exploratory well, YPF.Nq.LoAm.x-1 (Loma Amarilla), La Banda Block, Neuquén Basin. This block is entirely covered by volcanics from Auca Mahuida Igneous Complex. At the well location it was estimated 100 to 150 meters of surface volcanics.
So that, in this area, the 3D seismic volume acquired in 2003, presents a poor to fair signal to noise ratio; and low frequency content (Fmax ˜40 Hz). Fig. 1.
The main targets of this project were two igneous bodies, intruded as sills; the deeper one in Cuyo Gr.; and the shallower in the Vaca Muerta shales.
Fig 1: Visualization of Borehole, 3D Seismic, Satellite Image and Topography.
The presence of basalts in the area is affecting the recovery of high frequencies reflected in the subsurface; for this reason, surface seismic is very poor in terms of resolution and it is expected that the image obtained through the OVSP helps in the interpretation of the area. The job was planned in 2 phases, intending to acquire a ZVSP from surface to 2480m in the first phase, for the second phase a ZVSP from 2480m to 3580m and also an OVSP. The first VSP data was used to calibrate the model and determine the best position for the OVSP (based on survey design). In the second phase, Q factor was estimated using ZVSP, a migrated image was obtained
from the OVSP, and an Acoustic Impedance Inversion was performed using the ZVSP. Finally, all the information was merged to obtain a complete time-depth relationship, corridor stack and Q factor estimation.