Asphaltene precipitation is a challenging and complex problem in all sections of the oil industry including oil production, transportation and processing. Asphaltenes can plug pumps, valves, tubing and flow lines, cause fouling in surface handling facilities and even act as coke precursors and catalyst poisons. For these reasons, the occurrence of asphaltene deposits may result in productivity losses and sometimes even production shutdowns. For many years, much effort has been done on modelling asphaltene precipitation because experimental investigation is a hard task. Thermodynamic models based on Flory-Huggins theory have been used by several oil companies to predict the asphaltene onset conditions due to the depletion or gas injection. However, the main requirement to accomplish a successful calculation of asphaltene precipitation is an accurate solubility parameter. A variety of models to calculate asphaltene precipitation based on the solubility parameter is available in literature but most of them are complex due to inherent assumptions that are built-in. In this work, a new simple and accurate method to calculate the asphaltene solubility parameter is proposed, which requires only SARA (saturate, aromatic, resin, and asphaltene) analysis, the oil composition and the reservoir temperature. Once it is sufficient to know up to C7+ fraction, a much detailed analysis of the oil composition is unnecessary. Soave-Redlich-Kwong (SRK) (
Implementing a stochastic approach along with the conventional wellbore stability analysis enables to take into account uncertainty from input data in order to obtain more realistic and reliable predictions which improve decision making process in drilling operations. By means of the methodology proposed, the uncertainty assessment for each parameter can be addressed through distinct methods depending on available information, and a sensitivity analysis is used as complement to the Monte Carlo Simulation to identify those lesser impact variables which can be treated as deterministic values and so that processing time is reduced.
As result of this workflow, quantified uncertainties are propagated into model and probability distributions for collapse and fracture mud weights are generated, and a mud weight window as a function of success probability for drilling without instability problems is built. Ultimately, a study case is developed to assess the probabilistic mud weight window for a drilling process in a Cretaceous Colombian formation.
The design of wells into two sections (16? × 13 3/8? and 12 ¼? × 9 5/8?) in the Ecuadorian basin is a challenging effort of engineering. The success of the well depends on various techniques that will be analyzed in the following paper, which include precise casing seating depth, accurate fluid density for each section, appropriate formation bridging and sealing in the production zone (Napo), correct chemical selection as part of the fluid system to reduce formation damage on the producing reservoirs, plan a suitable directional trajectory if vertical section aloud (less than 2000') use "S" type design and appropriate BHAs for each section taking into account formation tendencies in terms to reduce slides in the case of PDM BHA is used. Other techniques applied that are going to be reviewed are include cementing production casing can be used slurries with higher densities to achieve better cement quality having less ECD during jobs; the two section design allows to run larger diameter guns and higher penetration bullets into productive sands, artificial lift systems can be set close to the producing reservoir. Using these techniques in the two sections design can provide several advantages compared with conventional three or four sections design in the Ecuadorian basin. This advantages are less cost for Drilling Event by time, by materials and equipment used, avoid adding risk when setting expandable 7? Liner Hangers, reduce risk of drilling tools and Wireline logs to get stuck related to higher clearance between them also Casings can run smoothly, improving production from reservoirs drilled through.
The result of first well drilled using these techniques will be presented in the following paper taking into account design facts, programs and procedures during the operation, and the results that will demonstrate the value of the design.
Almeida, R. (Petroamazonas) | Lomas, J. (Petroamazonas) | Madrunero, C. (Petroamazonas) | Castillo, M. (Petroamazonas) | Chicaiza, F. (Schlumberger) | Silva, A. (Schlumberger) | Contreras, C. (Schlumberger) | Korgemagi, A. (Schlumberger)
The Pañacocha field, located on the Northeast part of Ecuador, is part of the Block 12 from Petroamazonas EP in an ecologically sensitive area of the Amazon rainforest.
Heavy oil (less than 14°API) producers Ml and M2 formations in Pañacocha field are not being fully developed due to challenges of handling fluids with viscosities that increase exponentially as their temperature decrease.
This paper shows how the design, planning and installation of an inverted concentric dual completion string combined with the gravel pack technique for sand control and forced convection to minimize fluid heat transfer through the tubing, allowed to produce high viscosity fluids.
The phrase "a cleaner and environmentally attractive fuel," describes why the gaseous hydrocarbon, natural gas, is a favored fuel choice compared with other hydrocarbon fuels and coal. Its emergence as a preferred fuel has grown throughout the years and as such worldwide consumption and production have escalated.
Trinidad and Tobago is the top natural gas producer in the Caribbean with an average 2014 daily production of 4,069 MMscfd. With a vibrant upstream, midstream and downstream sector, Trinidad and Tobago makes maximum use of the natural gas value chain. Further maximization through growth in Trinidad and Tobago's downstream sector requires an adequate supply of natural gas in addition to the shallow water gas fields offshore Trinidad and Tobago which are currently the main supply source. Deep water gas fields have the potential to increase supply but unlike oil, the ease and economics of development are challenging. As a thriving gas sector, a myriad of infrastructure already exists which may aid with any further development.
An understanding of the magnitude of investment, its return to both operator and government and the well head price to economically produce natural gas from deep water fields is critical especially for potential domestic and Caribbean markets. For Trinidad and Tobago, an economic option to develop potential gas resources in deep water fields would bolster further downstream investment and by extension the economy. Regionally, potential markets can also be served via this supply. This paper therefore focuses on a deep water gas development strategy which utilizes Trinidad and Tobago's existing infrastructure. It presents a technical and economic evaluation of a deep water gas field based on three (3) recoverable resource sizes, one price structure and a production range of 500 mmscfd to 750 mmscfd. The development strategy along with associated capital and operational expenditure, Net Present Value (NPV) discounted at 6%, 8% and 10% nominal to January 2015, Government and Operator share percentages and internal rate of return (IRR) are highlighted.
The paper concludes that initial investment for a resource size of 3tcf to 5tcf would be between five (5)-eight (8) billion USD. Economic returns to both Operator and Government for these deep water, dry gas developments requires a well head price of greater than USD 3.50 per mscf. Government share % ranges from 19 % to 35% and for the operator, an NPV of USD 1.2 Bn to USD 2.3 Bn can be achieved.
Because of the operation in offshore platforms, sometimes it is impossible to change the location of any equipment due to time, space or costs. For these reasons it is important to be able to adapt equipment, and change its/their configuration without affecting its operation or efficiency.
This particular case is focused in the configuration change of chimneys of indirect heat exchangers, which operate with natural gas as a fuel, when natural gas of two production wells are heating through a water bath. The change of configuration of chimneys consists of relocating only the chimneys farther than the original locations next to the indirect heat exchangers located in the superior cover of an offshore natural gas production platform.
Before changing the original arrangement of chimney, it is important to evaluate the equipment behavior with its original configuration to know its behavior. After that it is possible to apply the principle of differential pressure because of difference of densities between ambient air and flue gases, called chimney effect or natural draught.
This phenomenon allows to compensate the pressure drop due to the increase of the length of line to send the flue gases to atmosphere, considering a sufficient height of the chimney. However, it is important to make an appropriately height estimation to avoid changes or affecting the performance and operation of the heating equipment.
Adaptations over the chimney systems of indirect water bath heaters with natural draft and natural gas as a fuel produce acceptable results in the equipment behavior without blower installation.
This paper shows that it is possible to change the configuration of the flue gases system of an indirect water bath heater to heat natural gas using natural draught without affecting its operation after the configuration changes.
An important key that shall be considered is the climatological variations that could affect the natural draught, and chimney diameter.
Heavy oil recovery from matrix blocks of Indiana limestone and Silurian dolomite core samples was studied using a cylindrical core holder set-up. Fractures in the system were represented by a gap between the core sample and core holder wall. Core samples and fractures were respectively saturated with heavy oil and gas. Oil recovery experiments were conducted in batch-mode using two different gases, nitrogen and carbon dioxide, at 1000 psi and various temperatures (200, 250, and 300 °C). N2 was employed as an inert gas to study the effect of temperature in oil production from the cores without affecting its chemical properties. Consequently, CO2 was used to investigate the role of mass transfer between matrix and fracture fluids in oil recovery.
The produced oil from the matrix was collected and the recovery factor for each experiment was calculated. Moreover, the remaining oil in the core was extracted. Viscosity determinations and simulated distillations of the two samples, produced oil and remained oil in the core, were carried out in order to assess oil quality distribution.
Experimental results revealed that with immiscible gas injection at high temperatures oil segregation occurred in the porous media. Consequently, lighter components of oil were produced while the heavier ones were left behind inside the matrix. Results also demonstrated a relationship between the amount of oil produced and the oil segregation in the porous media.
This research provides a systematic analysis to investigate the main recovery mechanisms from carbonate matrix blocks under various hot gas injection scenarios, which is of great interest to determine the most appropriate enhanced recovery method to be applied for heavy oil production from naturally fractured reservoirs.
Atahualpa, G. (Agip Oil Ecuador an Eni Subsidiary) | Venturino, G. (Agip Oil Ecuador an Eni Subsidiary) | Zerpa, E. (Agip Oil Ecuador an Eni Subsidiary) | Correa, R. (Agip Oil Ecuador an Eni Subsidiary) | Guleryuzlu, M. T. (Schlumberger) | Telles, J. (Schlumberger) | Morán, S. (Secretaría de Hidrocarburos Ecuador)
Drilling an exploratory well in highly sensitive environments imposes a number of challenges for an Oil Company. One of these challenges is to provide Heli-portable logistic coordination to achieve a successful drilled well in the most cost/time effective manner keeping in mind that hundreds of people, equipment, supplies and fuel have to be transported to and from the rig in the safest way
The initial time planned for the exploratory Oglan 2 Dir well was P-10: 32.7 days, P-50: 37.4 days and P-90: 49 days with an initial estimated NPT < 15%. The total duration of the well was 38.1 days, with an NPT of 15% due to operational difficulties encountered while acquiring downhole data and other operational events; however, 0% NPT was related to heli-portable logistics. Pre-established communication and responsibilities flowchart together with risk management allowed the achievement of goals and targets: coring 220 feet of Hollín Formation (main well target), acquire LWD on all the section and WL open hole logs in 81/2" section and, the most relevant goal, take fluid samples from Hollin and Napo Formations using a Saturn Tool.
This methodology and concepts can be used as a guide for any heli-portable and/or remote operations with a pre- defined management and communication workflow among Operator, Service Companies and Rig Contractor reaching the main goal to meet AFE time and cost.
Villanueva, G. (Schlumberger) | Burgos, J. (Schlumberger) | Humbert, O. (Schlumberger) | Betancourt, A. (Schlumberger) | Lopez, M. (Schlumberger) | Sandoval, L. M. (Schlumberger) | Arevalo, J. C. (Schlumberger) | Hurtado, J. (Schlumberger) | Meza, D. (Schlumberger) | Torres, C. (Schlumberger) | Gozalbo, E. (Schlumberger) | Vela, I. (Petroamazonas EP) | Egas, A. (Petroamazonas EP) | Leon, R. (Petroamazonas EP) | Loyola, R. (Petroamazonas EP)
Well evaluation is the primary method used in the oilfield to determine the true well's production potential and reservoir characteristics. During a well evaluation, downhole parameters are commonly registered using downhole memory gauges, which can only be retrieved and read after the evaluation have finished. The problem with this conventional method is the uncertainty or ambiguity results and the inaccurate data of the downhole parameters; which often lead to inefficient tests times and difficulties for well test interpretation.The use of Fiber Optic for Real-time downhole measurements conveyed on Coiled Tubing (CT) and Nitrogen (N2) Lifting provide a unique live insight that allow us to monitor the well response while production or evaluation is performed, eliminating the uncertainties that surrounds traditional methods.
Nitrogen lifting with Coiled Tubing was introduced as an alternative evaluation method for the common Hydraulic Jet Pumping that proved advantages accelerating well response and increasing the accurate of the reservoir data for well evaluation and artificial lift design nevertheless this still faces the delayed on the pressure data and transient interpretation. Implementing the Real Time downhole measures (P, T) is possible to eliminate uncertainties of reservoir parameters that surround well evaluations, adjust job parameters on-site, optimize job resources and time and finally anticipate artificial lifting design.
This paper will present the results of the implementation of this new method in the area for well evaluation allowing real-time measurements of down hole pressure/temperature. Combining the fluid lifting with N2 through the CT, reservoir response is continuously monitored; thereby, allowing in advance an adequate design of the lifting system reducing nonproductive time. Real-time measurements and accurately data of the reservoir allow defining if a further stimulation treatment is needed. Actual treatment program can be continuously monitored or modified, to achieve optimal results.
The first trial using the system demonstrated that the application can be used with a high degree of accuracy and control for the parameters and treatment designs that are not achievable using conventional techniques as the Hydraulic Jet pumping, gauges conveyed in slick line, joined tubing and/or using surface data to predict downhole behavior.
In an scenario that shows how expensive conventional drilling has become in Ecuador, with the aggravation of the oil price collapse, Operator's reaction was to opt a new strategy focused on optimizing drilling operations by managing some tolerable risks, which increase productivity, reducing time and costs in some specific directional wells, which brings economic benefits to the company and to the continuity of the development of any field through cheap drilling.
The proposed strategy is based on historical data and the application of productivity concepts are classified in three clear categories to be measured and optimize:
Productivity by time
Productivity by day
Productivity by man-hour
Putting these categories into a simple set of equations (operation/time), will enable any reader to see that variation in the quotient (time) in all of them is reflected directly in productivity value in an inversely proportion, hence directly affecting project costs. Therefore, companies are forced to manage their drilling time day by day.
It has been said that the critical factor in the total cost of a well is time, so the strategy proposed involves the reduction of drilling time by removing one whole section in wells that meet certain technical criteria. Eliminating a whole section along with proper risk management has enabled to lower costs in about 40% (this includes all tangible and intangible costs).
For the drilling department, the standard that has been set for selecting the number of sections per directional well and based on the horizontal displacement is the following:
2-section directional wells with displacements <= 3000 ft
3-section directional wells with displacement > 3000 ft
Presently, a two-section directional well from spud to Rig Release has a cost of about US$1.7 – 1.8 million.
Drilling Department in an effort to improve the productivity and achieve better performance on its operational activities, has focused to analyze technical concepts combined with the application of basic concepts of productivity presicelly in drilling engineering such as changing from 3 to 2 string well designs. These management of ideas from the engineering and operational point of view has allowed the operator drill faster at a lower cost. The optimal use of available resources, the right application of special tools and taking operational risks mitigated by a high level of management, has allowed achieving the expected success.
From a technical-financial point of view, these results are of great benefit to any operator.