Vertical modeling, a tool based on theoretical background, simulates the pressure response in a vertical well within a rectangular shaped reservoir with homogeneous characteristics. The objective of this study is to perform pressure transient analysis to estimate reservoir parameters of kailashtilla gas field based on pressure and production data. A vertical model is matched to pressure history as an inverse process to extract the reservoir parameters and compared with the estimated and Al Mansoory Wireline Services resultant parameters. Deliverability test is performed to measure production capabilities.
With the advent of downhole permanent gauge reliable gathering of flowing bottomhole pressure is on the rise. This essential bottomhole reservoir data is subtracted from the reservoir average pressure to calculate pressure drawdown. The resulting drawdown is commonly used to estimate well productivity index. In this paper we demonstrate how drawdown can be used to generate a decline curve which is extrapolated to estimate future recovery potential.
We show in detail how this method is used to estimate future production performance by linearization of drawdown-time curve and drawdown-cumulative curve and thereafter extrapolate the resulting straight-lines into the future.
The commonly applied method to estimate future recovery potential of a producing well is to plot its production rate against cumulative production or against time and thereafter extend the semilog straight-line to some economic limit. The point of intersection of the economic limit and the extrapolated straight line demonstrate the well ultimate recovery1. This method assumed that the past reservoir behavior is carried into the future such that the well future performance is controlled by
thesame past reservoir fluid dynamics. This assumption in which the extrapolated decline-curve is developed is usually amended when there are changes to the well production method1. There are three basic types of rate-time decline equations which are exponential, hyperbolic and harmonic equations1. The theoretical basis for these decline curve equations assumed that the well is in boundary-dominated flow such that the flowing bottomhole pressure, productivity index, skin factor, and drainage radius are constant.
Until now production decline-curve analysis has been carried out utilizing well production rates. The well rate is used because it is one of the most easily available data of a producing well1. As common as this data is it is seldomly measured on daily or monthly basis but allocated based on some measured well test rates. This allocated well production rates are utilized for production decline-curve analysis.
Nowadays, another readily available well data is bottomhole pressures. Not only is bottomhole pressures commonly available but it is measured at time frequency as high as per seconds thereby improving the accuracy of this readily obtainable well data. This regular well data measurement is made possible with the advent of permanent downhole pressure gauges that is installed in producing wells to measure high frequency bottomhole pressure data.
This paper demonstrates how measured well bottomhole pressure is utilized to develop a pressure-drawdown-cumulative curve and pressure-drawdown-time curve. The pressure-drawdown-cumulative curve is obtained by subtracting bottomhole pressure from average reservoir pressure and thereafter makes a log-log plot of drawdown pressure against cumulative production. The resulting straight-line is extrapolated into the future to yield ultimate recovery. The pressure-drawdown-time curve is obtained by making a log-log plot of drawdown pressure against cumulative uptime. The log-log straight-line is projected into the future to yield pressure drawdown economic-limit.
Gaspar Ravagnani, Ana Teresa F. da S. (U. Estadual de Campinas) | Costa Lima, Gabriel Alves da (U. Estadual de Campinas) | Barreto, Carlos Eduardo (U Estadual De Campinas) | Munerato, Fernando Perin (U. Estadual de Campinas) | Schiozer, Denis Jose (U. Estadual de Campinas)
After recent discoveries of large oil reserves in pre-salt areas of Brazil, the government has proposed a change in the current fiscal regime from Royalty & Tax to Production Sharing Contracts. The government wishes to implement the production sharing system to earn higher revenues, believing that this is the best policy to improve State gains to be transferred to society. In this new environment and focusing on the oil production strategy selection process, it is required to know if: 1) the production strategies are the same or different for both models 2) the same technical-economic indicators are suitable to be used to select the optimal production strategy in both systems. Nowadays, there is no clear convergence of points of view to answer these issues, although some debates among professionals and government are taking place. The aim of this paper is to present a comparative analysis of the optimum exploitation strategy for both fiscal models, regarding number of injection and production wells and, their allocation in the reservoir. This objective is accomplished following a production-strategy optimization that combines manual and automatic procedures to maximize the company NPV accounting for the assumption of a known behavior of oil prices. Sensitivity analyses of government take to oil price and cost recovery limits are carried out. The results show that the choice of the optimal-production strategy to maximize NPV depends on the fiscal regime. In addition, the government take is reduced with the increase of oil prices. For any oil price, the government take in the production sharing contract system is higher than in R&T, so that it is one of the reasons why it is more interesting from the government's point of view. Besides, the increase of cost recovery limit implies in a reduction of the government take up to a stable value.
Jardim Neto, Abrahao Teixeira (BJ Services Do Brasil Ltda) | Prata, Fernando Gaspar Miranda (BJ Services Do Brasil Ltda.) | Gomez, Julio Rodolfo (Baker Hughes) | Pedroso, Carlos Alberto (Petrobras S.A.) | Martins, Marcio de Oliveira (Petrobras) | Silva, Dayana Nunes (Petrobras)
Operators developing reservoirs and producing them from deep and ultra-deepwater wells are pushing the technical limits regarding horizontal extension. Deepwater wells completed in uncosilidated formations usually have low fracture gradients, severe leak-off zones and/or significant wash outs. Long horizontal open holes, therefore, may become technically difficult or economically unfeasible to gravel pack using conventional fluids and gravels.
Typical completions offshore Brazil start from a 9 5/8-in. or 10 3/4-in. casing, where a 5 1/2-in. premium screen and tubular string is hung along an open hole drilled with 8 1/2-in. or 9 1/2-in. bit. Horizontal extensions range from 980 to 4,000 ft.
Ultra-lightweight proppants have enabled gravel packing in these longer horizontal open holes. The reduced gravel density allows a significant reduction in pumping rate, which avoids fracturing the formation, minimizes fluid losses and eliminates the risk of premature screen out due to excessive gravel settling.
This paper summarizes the procedures and results of almost 60 wells that have been gravel packed using ultra-lightweight proppants technology pumped for a local operator.
1 - Introduction
Horizontal openhole gravel packs (HOHGP) have become the completion choice for many operators around the world, especially in permeable and unconsolidated formations. When it comes to deepwater and ultra-deepwater completions, operators have reached the limit as far as horizontal extension is concerned. Offshore Brazil, especially in the Campos and Espirito Santo basins, HOHGP has become the preferred completions methodology applied by the local operator to develop post-salt reserves.
The most common gravels pumped to pack horizontal wells offshore Brazil used to be natural gravels and several mesh sizes of conventional ceramics gravels. These particles' densities (from 2.65 to 2.73 g/cc) cause a high degree of difficulty with regards to proppant transport; hence, increased dune height may lead to premature screen-out might at low pump rates.
A lower-density proppant would be easier to transport with unviscosified fluids such as completion brines, thus allowing reduced pump rates to circulate proppant at the bottom of the screen and successfully pack the entire horizontal open hole.
Several authors have shown the applicability of modified black oil (MBO) approach for modeling gas condensate and volatile oil reservoirs. MBO approach could adequately replace compositional simulation in many applications (including water influx or water injection applications). Changing separator conditions during the history of the simulation run still needs compositional simulation, since PVT properties are calculated for specific separator conditions in black-oil and MBO approaches. Some commercial simulators have treated changes in separator conditions for black-oil applications. However, and to the best of our knowledge, no such treatment exists for the MBO approach. In field operations of volatile oils and gas condensates, however, separator conditions often change because these volatile fluids are usually separated through three and more separation stages, when wellhead pressure allows. We often see that the well stream is usually rerouted to lower pressure separators at later stage of the field life.
In this work, we derived two new equations that can be easily programmed into existing simulators and will allow accurate calculations of oil (or condensate) and gas rates when separator conditions change. These equations extend the use of MBO approach and provide an alternative to compositional simulation when field operations undergo changing separator conditions.
The inputs to our equations can be easily obtained from the EOS model used to generate the PVT tables for MBO simulation runs.
To validate our work, we generated many MBO PVT tables using Whitson and Torp method for a variety of fluids covering wide range of gas condensates and volatile oils. We applied our new equations to calculate oil and gas rates when separator conditions change for all these fluids. For validation of our approach, we then used fully compositional simulation and applied the same changing separator conditions and compared the rates, which compared very well. In the paper, we also show several field examples exhibiting large gas-oil ratio (GOR) and condensate-gas ratio (CGR) variations when separator conditions change, and the applicability of our technique on field data.
Modified Black Oil (MBO) Development
Coats 1 presented radial well simulations of a gas condensate that showed a modified black-oil PVT formulation giving the same results as a fully compositional EOS PVT formulation for natural depletion above and below the dew point. Fevang et al 2 obtained results which mostly support the conclusions by Coats. El-Banbi et al. 3,4 suggested that the MBO approach could be used regardless of the complexity of the fluid. They presented the results of a full field simulation study for a rich gas condensate reservoir. Whitson 5 noted that it should be realized that even when dealing with a slightly volatile oil (GOR>125 Sm3/ Sm3), a modified black-oil (MBO) PVT formulation should be used in reservoir calculation (material balance and simulation). El-Banbi et al. 6 found new correlations for oil-gas ratio (!!) of gas condensates and volatile oils. The correlation can be used in generalized material balance calculations and MBO simulation.
Bruni, Corrado (BG) | Sellami, Besma (British Gas Tunisia Ltd.) | Odumboni, Idowu Bashir (BG Group plc) | Turner, Marcus (Schlumberger Italiana SPA) | Sanguinetti, Marco (Schlumberger) | Kazmer, Jorge (Schlumberger)
The Abiod formation is the principal target in the Miskar field, offshore Tunisia. Consisting of fractured geomechanically stressed carbonate with a measured matrix permeability as low as 0.1 mD. The formation dates from Campanian to lower Maastrichtian and forms a horst structure. The formation has been under production since 1996.
Obtaining formation pressure data was considered critical for determining the magnitude of depletion from production, wellto- well comparisons for vertical and lateral connectivity, forward modeling, completion decisions, and refinement of the field development plan. Historically, this has been a challenge with conventional wireline (WL) formation testers for the following reasons:
• Severe depletion and well deviation causing differential sticking
• High temperatures (150 to 195° C) at the limit of tool electronics
• Low permeability
• Fractures and breakouts that can impact seal success
This was overcome with a systematic multidisciplinary approach. After review of historical formation testing data, and influence on seal success with probe vs packer elements, it was decided to apply formation-pressure-while-drilling (FPWD) technology. The key questions with FPWD in this environment are: Can we achieve a good transient profile and what is potential impact of supercharging? These questions were addressed with advanced prejob modeling, which enabled determination of an optimized pretest configuration and testing procedure to minimize potential supercharging effects.
While drilling, stage-in procedures were used, and mud logging total gas data were gathered to identify areas of liberated gas. Pre-run wireline petrophysical data were gathered to characterize the Petrophysic of the reservoir and to calculate an intrinsic permeability profile. Ultrasonic borehole images and caliper data were used to determine the principal horizontal stress directions, fracture frequency, and orientation and to confirm the stratigraphyc dipping of the structure. Combined, this information allowed a focused orientation of the FPWD probe and optimal station selection avoiding fractures and breakouts.
This novel approach resulted in 100% seal success, >50% improvement. Four days of rig time were saved, and the required data were obtained.
The offshore Nile Delta is an established and significant gas and condensate province in North Africa. It is considered to have significant remaining hydrocarbon potential for future exploration. The main petroleum system comprises of an Oligocene Type II/III mixed oil and gas prone source rock which charges the overlying thick sequence of Neogene-Quaternary clastics. While the hydrocarbon potential of the Nile Delta and its geological and stratigraphic pattern has been the focus of numerous studies, the origin of the gas and associated fluids has been poorly documented.
In order to characterize the natural gas at the study area, an integrated geological, geophysical and geochemical study was performed on 439 gas samples and 493 cutting samples collected from 7 wells in addition to a review of published work covering the origin of natural gas and associated fluids.
The analysis shows that the gases are dominated by methane (97%-100%) and the light carbon isotopic composition (d13C1) values (-57.4‰ to -80‰) suggest that these gases are derived from the decomposition of immature (0.3-0.6 Ro%) sedimentary organic matter by Methanogens activity under relatively low temperatures (<80 °C).
The paper will give an overview of the integrated work, focusing on the geochemical analysis used to describe the occurrence and character of the natural gases in the study area.
In developing most deepwater fields with limited number of wells, intelligent well systems which consist of many valves and sensors are employed to maximize production capacity under facility constraints. Analysis of sensor data unaffected by wellbore effects allows operators to estimate key reservoir parameters, well capacity and calculate actual flow rates at zonal level. Decisions for operational control is made based on data analysis, the result of which is used to optimize overall field performance and maximize return on investment.
Understanding pressure sensors placement issue is important from pressure-transient analyses viewpoint. Pressure gauges should ideally be placed as close to the perforations as possible to ensure the pressure data is unaffected by friction in the tubing between the perforations and pressure gauges but placement of the gauge is dictated by completion hardware configuration and can be located far away from the point of reservoir fluid entry. This may result to potentially erroneous measured pressure data and may lead to the calculation of inaccurate reservoir parameters and an overestimated mechanical skin value from pressure buildup response.
One of the main operating constraints in deepwater wells is flux limit which is a practical well surveillance tool used to monitor and operate sand control completions, maintaining each producing interval at a maximum safe operating rate, and also monitoring well impairment to allow for proactive remedial operations. Since the flux limit is a function of mechanical skin, if the mechanical skin is over estimated because frictional losses are not properly accounted for, well production may be unnecessarily constrained.
In this paper, analysis was done using a wellbore/reservoir simulator to account for frictional effects in the tubing between the perforations, and the gauge for a field example. Sensitivity analysis was also carried out at different flow rates for each well and simple correlations were developed for predicting frictional effects. Results obtained from calculations showed that pressure gauges placement effect is significant as flow rate and gauge distance from perforations increases. Correcting for this effect increased the flux limit thus increasing production rate on several wells that were previously flux constrained.
Worldwide, as conventional oil resources are depleted, beam pumping system is becoming the most common type of artificial lift methods for onshore wells. Production testing of beam pumped wells is an important diagnostic tool to detect potential production problems and for monitoring reservoir performance. In addition, well test data and the Inflow Performance Relationship (IPR) combined with the production data help to design, analyze and optimize the whole well production system. With the growing number of beam pumped wells, the value of such data is increasing over time.
Published literature and field experience show that the traditional well testing methods for beam pumped wells have various limitations such as being hazardous, have a lot of assumptions, provide only a snapshot data and are costly processes. On the other hand, well testing is problematic if the wells are isolated or at a far distance from the field facilities. Also when large population of beam pumping wells are connected to central batteries, it is difficult to determine the daily production of each well or to identify the cause of low production in the battery, as there is not an easy way to identify which well is affected.
This paper will discuss a technology that started to replace traditional well testing facilities or at a minimum a new way to verify individual well performance on a day by day basis. The new method continuously infers the production and calculates the corresponding bottom-hole pressure using a smart rod pump controller system located at the well site by analyzing the downhole pump card data. The basic logical assumptions and methodology of the new method are summarized to give an understanding of how the test is implemented and under what conditions the test will be accurate. Real field data are shown and compared with data acquired by other traditional methods.
As the beam pumping system is the most common type of artificial lift methods and the majority of onshore wells are produced by this method, the need for accurate and continuous performance monitoring and production testing analysis for beam pumped wells is vital. Also with the growing number of beam pumped wells the value of such data is increasing over time. The most important parameters that need to be measured during well testing are the flow rate and the bottomhole pressure (dynamic and static). The application of the pressure transient theory to evaluating well tests requires that accurate bottomhole pressure measurements be made. In the case of wells that are producing by beam pumping system, the direct measurement of bottomhole pressures is very difficult, since the presence of the pump in the tubing physically precludes the use of wireline pressure gauges and permanent downhole pressure installations are usually not economically attractive.
This paper will illustrate a technology that started to replace traditional well testing facilities or at a minimum a new way to verify individual well performance on a day by day basis. The SMART WELL TEST (SWT) method will be discussed which continuously infers the production and calculate the corresponding bottomhole pressure using smart rod pump controller system located at the well site. Also, from the SWT, any change in well production can be known in real time by analyzing the downhole pump card.
Bhaisora, Devesh (Halliburton Overseas Ltd.) | Paton, Nestor (Halliburton) | Waheed, Arshad (Halliburtion) | El Nashar, Radi (GUPCO) | Farouk, Mohamed (GUPCO) | Soliman, Fathy Mohamed (Gulf of Suez Petroleum Co.)
This paper highlights a successful cement job in which more than 1,300 bbl of cement slurry was pumped to help cement the longest 9 5/8-in. casing in a highly deviated and washed out wellbore in the Gulf of Suez (GOS). This novel slurry design aided efficient cementing across a massive salt section, while mitigating the risks associated with using a multiple-stage cementing tool in highly deviated wells.
To access most of the reservoirs in the GOS, operators must drill through a salt section with a thickness sometimes greater than 1000 m. This section is covered with 9 5/8-in. intermediate casing, which is generally cemented in two stages using a multiple-stage cementing tool. Conventional salt slurries of 15.8- to 16-lbm/gal are generally used to cover the salt section.
Any failure with the multiple-stage tool can lead to expensive remedial work and can cause salt instability resulting from longer exposure, which can lead to salt creeping or loss of the well. The success ratio of multiple-stage tools is not high, especially in highly deviated wells; therefore, it was necessary to find a new approach to help mitigate the risks associated with using multiple-stage tools.
High-strength, low-density (HSLD) slurries have been successful in replacing conventional 15.8- to 16-lbm/gal slurries across the production zones. With this in mind, lightweight salt slurries were designed to replace conventional salt slurries across the salt section.
Because this is the longest intermediate casing in the GOS to date for the operator, it was logistically favorable because the lightweight slurries helped reduce the amount of dry cement required to meet the rig capability.
The cost of the multiple-stage tool, additional dry cement, dry-cement-transportation costs, and rig costs for waiting on cement (WOC) for the second stage were either completely eliminated or minimized with this solution, resulting in a total savings in excess of USD 100K.
Most of the wells in the GOS for the operator follow a common casing design (Table 1). Intermediate casing is set across a massive salt body known as the South Gharib formation. This section is drilled through the South Gharib formation and casing is set at the bottom of Belayim formation. In some cases, intermediate casing is set at the bottom of South Gharib as well. Further, the reservoir section is drilled with a lower mud weight and a drilling or production liner is run. Intermediate 9 5/8-in. casing is cemented in two stages, considering that some sand streaks in the Belayim might have a lower fracture gradient, and single-stage cementing using conventional 15.8- to 16-lbm/gal cement slurry can initiate heavy losses and expose the salt formation. A pore-pressure and fracture-gradient profile for the well is shown in Fig. 1.