bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimized Reservoir Development Using High Angle Wells, El Furrial Field, Venezuela
Authors: Smith Richard W. , Colmenares Rodolfo , Rosas Eulalio , Echeverria Isaura
Published: December 2007

The El Furrial field is one of the major field assets of Venezuela and is operated by PDVSA (Petroleos de Venezuela, S.A.), the national oil company. Its current production of over 450,000 BOPD makes it a giant oil field. Development of the field, which has an average reservoir depth of approximately 15000 feet, is in its mature stages due to implementation of high-pressure gas injection. PDVSA has consistently followed a forward planning approach related to reservoir management. Using high angle deviation drilling techniques allows development wells to be strategically located by penetrating the reservoir at high angles to optimize production rate, extend well life, increase reserves per well, reduce operating expenses, and reduce total field development costs.

A reservoir model was constructed and simulated using detailed reservoir stratigraphy to determine realistic potential of high angle wells. Five wells have been drilled as of June 2000 and the first four wells have proven the effectiveness of the design. The philosophy, the modeling technique, the well design considerations, the problems encountered, well results, and economic criteria provide a clear understanding of the risk of this technology not previously used at this depth in Venezuela. The result was the first high angle well in the deep, challenging environment of eastern Venezuela, followed by four others.

Results show that optimization objectives can be attained using high angle wells (HAW), mainly increasing per-well production rate, maximizing per-well recovery and extending the break-through time of gas or water from pressure maintenance and enhanced oil recovery projects. Well results indicate the geological and simulation modeling technique is reliable and accurate. A pilot program shows HAW technology provides major advantages to increase production rate and to reduce the overall number of wells needed to reach production objectives. However, the project also has experienced a number of unexpected drilling problems. 1

The costs associated with the total project are significant but more importantly, this program becomes very attractive due to: Long-term benefits of decreased water-cut related to current water injection.Decreased gas breakthrough due to high-pressure gas injection.Fewer wells are required to meet production goals.

The technical contributions include: The modeling technique of applying detailed stratigraphy to a full-scale reservoir model is accurate if performed with the appropriate objectives in mind.The application of state-of-the-art drilling techniques to attain high angles at deep drilling depth is possible. However, drilling problems caused by formation instability require more study and experience.This method can be applied to other fields in the eastern Venezuelan basin currently under, or planned to be under, enhanced recovery programs and development programs.
Underbalanced EMWD-AP At La Concepción Block, Maracaibo Basin, Venezuela
Authors: Romero F. J. , Pi D. , Cinquegrani A.
Published: December 2007

High deviation angle and a highly fractured carbonates reservoir with abnormally low pressures (depleted) were the greatest challenges in the drilling program to develop the deep objectives of La Concepción field. The development of an underbalanced drilling system was required to overcome the massive loss of circulation and associated problems.

An electromagnetic down hole telemetry system was selected to allow the acquisition in real time of measurements of well bore inclination, annular bottom hole pressure and temperature. This system is not dependent of the circulating fluid nature (liquid, gas or a mix of them) to transmit the information up the hole via sonic waves.

Consideration specific to this project ranged from simple ones, like the relationship between the formation pressure and the conditions and rate of injection of mud and nitrogen, to complex ones, like optimizing directional drilling trajectories, determining the minimum allowable equivalent circulating density to maintain stable wellbore, or establishing the minimum antenna height required to transmit the information from the bottom hole measurement tool to surface.

A combination of all these equipment and techniques has enabled us to drill 5 re-entry well bores and four new wells. The new wells were drilled underbalanced but without directional control.
Team Philosophy, Straight Hole Drilling Device and Performance Based Contracting Strategies Continue to Cut Drilling Costs in Tectonically Active Basin
Authors: Vargas Carlos , Rueda Fernando , Marquez Hugo , Pacione Mario , Cruz Marco
Published: December 2007

Drilling through steeply dipping formations associated with major structural features in the Sub Andina Basin of Northern Argentina presents several unique challenges. Specifically, formations in the upper hole sections (22" and 16") are typically hard, abrasive and prone to bit balling. Historically, these intervals have caused operators working the basin major drilling problems such as low penetration rates, hole deviation and frequent drill string failures.

Recently, the use of a Straight Hole Drilling Device (SDD) used in conjunction with a team philosophy and performance based contracting strategies has had a beneficial impact on drilling economics. Because prospects in the area frequently require drilling a well on the apex of a very narrow structural feature, there is a high risk of sliding through a high dip formation with very little change in wellbore trajectory. The SDD provides a unique technological solution to this challenging issue. As technical justification to run the tool, a novel commercial arrangement was established by benchmarking performance of wells drilled with conventional equipment. Then, a contract was structured where the operator did not pay for the use of the SDD unless it shortened drilling days to top of reservoir relative to the baseline wells. The tool was used for the first time in Northern Argentina in Macueta field cutting the drilling by 30 days compared with the best offset well in the Basin. Recently it was used again with the same operator in San Pedrito field saving 63 days relative to the last well drilled in this area. This paper will describe that accomplishment and outline how the team plans to incrementally improve on this success by: Introducing lower speed 9-1/2" motor to SDD tool to allow more WOB.Increasing weight on SDD tool from 80 klbs to 100 klbs would be possible due to change to low speed motor.Improve bit bearing life to end premature seal failure.Improving steering capabilities of SDD tool allowing for a 50 % increase in lateral force.Control solids, sand content and LCM to prevent from plugging and washing the tool's pulser and drill pipe screens.Use shock sub where appropriate.
Performance of a Foamy Oil Reservoir in Pseudo-Undersaturated State with Associated Aquifer
Authors: Yrigoyen A. , Carvajal G.
Published: December 2007

Heavy and extra-heavy oil reservoirs, with moderate gas oil ratio have additional primary recovery mechanisms that increase oil production. Morichal-01 reservoir is located close to the Orinoco Oil Belt, approximately 100 km South of Maturin city, Monagas State, Venezuela. This reservoir has a peculiar behavior and shows an additional recovery mechanism called by some researchers as a foamy phenomenon.

Such phenomenon occur, at the bubble point pressure, when the remaining gas in solution comes out of solution forming a dispersed trapped free phase inside the phase oil (as layer, it is not a free movable phase), as a consequence, no pressure drop is observed, i.e. pressure is maintained constant. Also flash GOR is constant. As a result, there is a progressive increase in oil recovery due to internal expansion of the gas bubbles.

This study aims to explain the peculiar behavior of the reservoir making some adjustment on material balance equations in order to find equations of Drive Depletion Index (DDI) caused by solution gas. All this is caused by solutions gas and free gas bubbles in the oil as well as oil compressibility. Some physical equations that govern foamy oil performance, formation oil volume factor, gas oil ratio and trapped free-gas coefficient (a) in the presence of pseudo-undersaturated state, will be presented.
Optimization of a Mature Oil Field by Changing Lifting System
Authors: Prado Pablo , Brarda Mario
Published: December 2007

All wells in Entre Lomas Area, after a initial period of natural flow, requiered an artifitial lifting system. Gas-Lift system suited very properly the field characteristic.

As the reservoir pressure declined and the water-flooding expanded, it became necessary to change the lifting system progressively from Gas-Lift to Sucker Rod Pumping (SRP) or Electrosubmersible Pumping (ESP).

With almost half of the wells already converted, the remaining did not appear economically attractive for conversion at the individual well basis. Therefore, a global conversion project for the remaining wells was considered, which ultimately yielded additional profit that made total replacement affordable.
Field Experiences in Evaluation and Productivity Improvement Using Selective Hydraulic Fracturing in Deep Directional Wells. Orocual Field, Venezuela
Authors: Carvajal G. A. , Ortiz K. , Carmona A. , Parra G.
Published: December 2007

Until 1998, eleven vertical wells had been drilled in Deep Orocual Field in Eastern Venezuela for a total of 16 completions to produce light oil and condensate. By hydraulically fracturing these wells, the productivity improved up to three times compared to the initial rates. The use of new technologies in drilling directional wells allowed the construction of three of these wells wells in the San Juan Formation.

This paper resumes the experiences associated to three wells in the Orocual Field, the evolution of operational practices and data acquisition that had to be implemented in order to, in some cases, overcome the effect of early stage screenouts and properly evaluate the productivity of such wells. Additionally said, experiences allowed the comparison of the fracturing techniques applied in these case studies, with the conventional designs used in the past and to establish the best evaluation and stimulation techniques for the San Juan Formation wells.
Improved Reservoir Permeability Models From Flow Units and Soft Computing Techniques: A Case Study, Suria and Reforma-Libertad Fields, Colombia
Authors: Soto B. R. , Torres F. , Arango S. , Cobaleda G.
Published: December 2007

This paper presents a methodology that looks to solve the inverse problem of predicting reservoir properties on uncored intervals/wells, using soft computing techniques (neural networks and fuzzy logic), multivariate statistical analysis and hydraulic flow unit concepts.

Our methodology to improve the prediction of permeability in Suria and Reforma-Libertad fields in Colombia is the following: Data quality control. We apply multivariate statistical analysis for quality control of core and log data: 95% confidence ellipses and Q-Q plots are used for that purpose.Rock type identification. We use poral geometry analysis to identify rock types in cored wells. Then, fuzzy logic, core and log variables are used to develop a rock type model to be used in solving the inverse problem, predict the rock type in uncored intervals/wells.Hydraulic flow unit classification. For that purpose, we use the technique based on a modified Kozeny-Carmen equation to calculate the reservoir quality index, RQI=0.0314(K/φ) ½, flow zone indicator, FZI=RQI/(φ/(1-φ)) and φz=φ/(1-φ). The basic idea of hydraulic flow unit (HFU) classification is to identify classes that form unit-slope straight lines on a log-log plot of RQI vs. φz with similar but not identical FZI value. Each class or hydraulic flow unit has a mean FZI value at the intercept with φz=1, and a maximum and a minimum FZI values. We use log data and the fuzzy logic rock type variable to develop a neural network FZI model to be used in solving the inverse problem, predict FZI in uncored intervals/wells. The HFU for each uncored interval is determined with its FZI value that falls on a range between maximum and minimum values of FZI. Finally, permeability is calculated knowing its porosity and FZI values.

In the literature, the HFU is first determined by Bayesian inference assigning a probability distribution of log values to each HFU and identifying to which population the given set of log readings most likely belong. Then, permeability is estimated from porosity and mean FZI values ignoring the scatter data for each HFU.

Permeability estimations from our approach are compared from other conventional techniques to demonstrate that this is a better way to get confident permeability models and to show how to used soft computing techniques to improve reservoir description.
Cyclic Steam Injection Pilot, Yacimiento Los Perales
Authors: Pascual M. R.
Published: December 2007

This paper describes the studies, implementation and results of the first cyclic steam pilot project in the Los Perales Field located in the San Jorge Basin, in the province of Santa Cruz, Argentina. The presentation also includes a brief description of the usual steam injection methods; these methods are widely used in the on-going thermal operations around the world.

Preliminary studies showed the feasibility of injecting steam in intervals with heavy oil located in the Bajo Barreal formation at a depth of 3300 ft.

Some reservoir characteristics are: Fluvial systems with multi-layer reservoirs mainly conformed by packages of four layers and three packages by well on average. The distance between these packages can vary from 262 to 328 ft.Viscosity ranges from 300 to 10000 cp, which varies from well to well and layer to layer.

The pilot project consists of four new wells that were designed and drilled specifically for steam injection. After injecting the pilot wells we decided to stimulate an old reconditioned well with the intention of evaluating the possibility of stimulating this type of wells.

The surface equipment includes a 25 MMBTU/h steam generator at a pressure of 2500 psi.

The steam injection started at the beginning of 1999 in well 804, with the following characteristics: Injection periods: 18 days with flow rate and pressure of 820 bbl/d (cold water equivalent, CWE) and 1800 psi (wellhead pressure, WHP). Steam temperature of 625 deg-F (wellhead temperature) and a steam quality of 65-70% at the sandface.Soak Period: after the injection period, the well was shut-in for 1 week.Peak oil and water production rates occurred within 1-3 weeks, being the initial response three times the primary production with a maximum rate of 27 m3/day in the well 804. The well produced almost a year before it reached the forecasted primary oil production. The history match had a good fit with the Gontijo & Aziz(1) analytical stimulation model that was prepared by the people of Repsol YPF.The well is being prepared for the second cycle.

Throughout 1999, the rest of the wells were steamed, the individual characteristics are being analyzed in detail.
A Web-Based System to Link Asset Tracking to Performance Improvements in Oilfield Operations
Authors: Slezak M. Steven , Prather Floyd
Published: December 2007

Many oilfield service companies as well as oil producers have manually tracked assets over the years for a variety of reasons. The service companies have tracked assets such as pumps, packers, or other products to assist in R&D efforts. Being able to collect the data and compile statistics on run times and component failures enables the service companies to evolve and improve current products as well as design new products. From a producers perspective, compiling the same or similar data allows for the development of "best practices" in operating procedures and processes. Software products developed to address these needs have evolved with time to provide more functionality. However, many systems implemented to handle the total process of data acquisition, warehousing, querying, and reporting to achieve improved operating results have become more difficult and expensive to support than the value added.

The value of the information has not diminished, but increased due to the fluctuations in oil prices and the continuing efforts to reduce lifting costs through design and process enhancements. The recent development of a web based tracking system incorporates workover management, downhole equipment, and chemical usage while enabling the operator and service provider the ability to easily enter and access the data. The system reduces the problems of database synchronization, multiple entries of the same data, and provides a common means through the Internet to interface with the information. The system links the operator in the field, the service company providing equipment or chemicals, and the district office together through a common database that each has access to.

The system allows a technician in a pump shop, workover foreman in the field, or chemical sales person to easily enter data into the system using a laptop computer or touch screen technology. The data is brought back to the service provider's local office and is accessible to the operator through the Internet. Wells, well equipment, and equipment components can be tracked for run life and root cause of failure. The operation becomes an information network that uses the same data to accomplish different tasks but with a common objective of reduced costs and improved profitability.
Evaluation of Displacement Efficiency in Volatile Oil Reservoirs under Nitrogen Injection
Authors: Rivera de la Ossa Juan E. , Correa Castro Juan C. , Mantilla Uribe Cesar A. , Duarte Prada Cesar Augusto
Published: December 2007

It nitrogen injection has been proven as a competitive alternative for volatile oil reservoirs lately found in Piedemonte area of Colombia, taking into account the reservoir fluid nature and the reservoir conditions. A laboratory study was carried out by the authors in the Enhanced Oil Recovery Laboratory of Colombian Petroleum Institute.

Three corefloods were carried out using Berea sandstone and volatile oil samples from the Piedemonte area and nitrogen as displacing agent. One of these corefloods was conducted in a long Coreflooding apparatus, and the other ones, in a short Coreflooding apparatus connected with a slim tube in a order to achieve miscibility conditions. The main variable studied was the flow rate, which represents three different flow regimes. The scaling criteria taken was a dimensionless group, which relates viscous and gravity forces, called gravity number.

Displacement efficiencies determined were around 50%, 65% and 80% for each one the tests. The results of these corefloods were compared to determine the best scheme of nitrogen injection. Results have successfully confirmed the effectiveness of nitrogen as displacing agent for this kind of oils and the better swept efficiency given by the equilibrium between the governing forces.
Gas Coning in Vertical and Horizontal wells, a Numerical Approach
Authors: Benamara Ahcene , Tiab Djebbar
Published: December 2007

In the presence of gas cap, production from a well is limited by the maximum, critical oil flow rate. If oil production rate is above this critical value, gas breakthrough occurs. After the breakthrough, the gas phase may dominate the total production rate to the extent that further operation of the well becomes uneconomical and the well must be shut in. In the oil industry this phenomenon is also referred to as "gas coning."

Until recently, several techniques have been used by the industry to prevent gas breakthrough due to coning. These methods include: keeping production rates below the critical value, perforating as far from the initial gas-oil contact (GOC) as possible, or creating a gas-blocking zone around the well by injecting crosslinking polymers or gels. Unfortunately, all these conventional methods do not solve the gas breakthrough problem.

It is usually uneconomical to keep production rate of a well below the critical rate. Perforating far above the GOC reduces the length of the perforation interval and, thus, increases pressure drawdown around the well. The increased pressure drawdown may enhance gas coning.

Despite the fact that the coning has been studied extensively since the fifties, it is still difficult to answer to the following two questions:

How to perforate a well subjected to the coning? What is the optimum oil flow rate of the well?

In this paper a numerical approach is used to study the gas coning using a 3-D radial model, and gas dipping using a 3-D irregular cartesian model, where well A, from Hassi-R'mel field in Algeria, is chosen for a case study.

In the first part, a sensitivity study was performed to analyze the most relevant parameters that affect the coning. In the second part, a new technique is proposed to interpret the variation of the different parameters that affect gas coning. It consists in plotting the free gas oil ratio (GOR-RsBHP) against the cumulative oil production on a log-log scale. This model reveals straight lines that occur after gas break through. In the last part of this study, regression analysis was performed to develop empirical gas coning correlations to predict critical oil rate, gas breakthrough time and gas oil ratio (GOR) after breakthrough for both vertical and horizontal wells.
Packers Designed for Coiled Tubing Completions, Recompletions, and Stimulation
Authors: Scott W. Sid
Published: December 2007

This paper includes mechanical, hydraulic, and inflatable packers designed specifically for use with coiled tubing in completions, recompletions, stimulation and cement work. Illustrations of current use of these packers are discussed: Velocity Strings, Tubing Patches, Tail Pipe Extensions, Gas Lift and Jet Pump Installations, Gravel Pack and Sand Screen Control, Wellhead Repairs, Zone Isolations, and Straddle Stimulation/Testing.
Reservoir Stress Changes Induced by Production/Injection
Authors: Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

This study uses a 2D poroelastic plane-strain model, together with Mohr's circles, to show some basic behavior of the reservoir stress field during production or injection. The flow-induced horizontal total stress field is analyzed for the evolution, distribution, orientation, maximum vs. minimum, and tension vs. compression. Changes in reservoir horizontal total stresses depend on production/injection mode: become less compressive during production (decreasing fluid-pressure) and become more compressive during injection (increasing fluid-pressure). Furthermore, these changes are anisotropic (i.e., different magnitudes in different directions). The horizontal differential stress, however, tends to stabilize for sufficient large time.
Slug Flow Model for the Prediction of Pressure Drop for High Viscosity Oils in a Horizontal Pipeline
Authors: Colmenares J. , Ortega P. , Padrino J. , Trallero J. L.
Published: December 2007

A modified mechanistic model is formulated to predict the pressure drop in horizontal slug flow for two-phase flow (viscous liquid and air). The model is evaluated by using accurate PDVSA INTEVEP experimental data for liquid with viscosity of 480 cP. A comparison between the modified model and experimental data shows that the absolute average relative error in pressure drop prediction is less than 6%.
Precise Well Placement using Rotary Steerable Systems and LWD Measurements
Authors: Tribe I. R. , Burns L. , Howell P. D. , Dickson R.
Published: December 2007

This paper demonstrates profitable geosteering of a Central North Sea, UK horizontal well by using a Rotary Steerable System (RSS) together with new generation azimuthal Logging While Drilling (LWD) tools. The nature of the Tertiary Turbidite reservoir meant that to be commercial the following criteria had to be met: Maximise stand-off from an oil water contact within a sand unit with a circa 50 ft oil column.Achieve 1500-2000 ft of good quality reservoir.While maintaining the stand-off from the OWC, make a corresponding azimuth turn in order to follow the crestal dome structures of the reservoir trap.Avoid the risk of stuck pipe by carefully monitoring real time drilling and well data and by using RSS technology.

During drilling of the well, correlation software enabled comparison of offset well and real time LWD data and visualisation of the position of the well in the reservoir sequence. This modelling complemented wellsite biostratigraphic and geological correlation work and enabled changes to the trajectory to be planned, which were then achieved while constantly rotating using the RSS tool. Azimuthal density measurements were used in real time and as post-well image logs for structural dip and fault interpretation.

The well was geosteered into a sweet spot within 5 ft of the reservoir roof as much as 56 ft from the OWC. The RSS tool completed the well in a single run of 3844 ft with an average ROP of 68 ft / hr and with no stuck pipe problems. The target of 1500-2000 ft of pay was met with 1980 ft of >20 % porosity sand and 88% nett to gross. Water saturation of 10% was much lower than expected and the well is currently producing at 11,500 bopd.

This well demonstrates the combinability of the latest RSS and LWD technology to successfully meet ever-demanding drilling and geological objectives under circumstances of high-economic risk and ultimately maximise potential well production.
Real Option Evaluation of a Satellite Field in the North Sea
Authors: Galli A. , Jung T. , Armstrong M. , Lhote O.
Published: December 2007

This case study is on a satellite close to a large gas and condensate field in the North Sea. At present one well has been drilled. The discovery well will be recompleted as a producer and one or two more producers are envisaged. These could be drilled straightaway or scheduled sequentially, in which case a revision of the project will be carried out. This paper presents a new way of sequentially updating the technical parameters (e.g. size of reserves, productivity of wells, etc) in response to new well information and incorporates this into a real option evaluation of the whole project.

The production scenario is that the project is stopped as soon as the costs exceed the revenue. Two different models (Black and Scholes and a mean reverting model) have been used to describe fluctuations in the oil price on which the gas price is indexed. Monte Carlo simulations have been used to evaluate the three development options (1 or 2 extra wells, drilled immediately or sequentially) for both price models.
Health, Safety and Environment Impact Assessment for Onshore Sour Gas Wells
Authors: Rezaei C. , Al Mehairy M. M. K. , Al Marzooqi A.
Published: December 2007

It is recognised that the drilling of high sour gas wells entails higher risk to workers, more complex drilling procedures and potentially higher concequences should a well failure occur. The sour gas well studied is known to contain 36% vol/vol of H2S which in the event of a blowout could have a significant impact. Concentrations capable of causing health difficulties could occur over 30 kms from the wellsite. Sour wells with high H2S release potential or those near dwellings require site specific emergency response plans. In case of a significant release of H2S, the health & safety of the public will be protected either by their evacuation or ignition of the well. At night, with stable conditions, the dispersion distances may be increased by a factor of 10.

The emergency response plan comprises an Emergency Planning Zone (EPZ) of 4-km radius and Emergency Awareness Zone (EAZ) of 8-km radius of the sour well. This study combined both an HSE impact assessment of a sour gas well, and a review of the adequacy of the risk management tools for associated drilling operations. Hardware & software measures are introduced to reduce the frequency of well incidents. The principle environmental concerns are potential impacts to air quality associated with flaring or uncontrolled releases of sour gas with high levels of H2S. The environmental impact of this well is within acceptable limits and largely unaffected by the reservoir composition. Waste management at each well site remains the key focus, irrespective of well composition. There are no long-term environmental impacts anticipated, except the loss of vegetation and wildlife habitat associated with the new access roads/wellsites. It must be ensured that the drilling management system identifies the requirement for a HSEIA sufficiently early to allow full incorporation of the findings.
Economic Real Time Fracture Optimization Using Bottomhole Monitoring Systems
Authors: Shepel T. D.
Published: December 2007

Fracturing operations continue to become more sophisticated in design, execution, and evaluation. The advancements in fracturing fluid technology and the increased complexity of fracturing operations have made the already complicated task of calculating an accurate bottomhole pressure (BHP) very difficult. The industry continues to struggle with the complexities of calculating an accurate BHP.

This paper address a technical application of a real time bottomhole pressure and temperature system, which has allowed operators to obtain real time data economically during the fracturing process; including pre-fracture build up, mini fracture, main fracture treatment, flowback, and well production data.

Case studies demonstrate how the bottomhole pressure differs from the calculated value during the fracturing operations. Engineers are better able to make pro-active decisions to optimize the operation, either from the field or from the office, based on the more accurate BHP. In several instances, the main fracture treatment was re-designed after the mini fracture analysis based on an accurate BHP. The paper reviews the theory on how the bottomhole pressure is calculated; shows the many uncertainties related to the calculated BHP; and with case studies, shows the value of accurate bottomhole pressures.
Instrumented Oilfields: Downhole Production Allocation by Passive Acoustic Listening
Authors: Haugen O. , Fallet T. , Nyhavn F.
Published: December 2007

Passive acoustic listening is relatively simple to implement in downhole equipment and has an interesting potential for downhole measurements. During a flow loop test at high temperature and pressure, SINTEF measured the acoustic noise inside a choke valve and developed an empirical model for prediction of flow rates of gas, oil and water. The accuracy is better than 7% FSO. An accuracy of 5% FSO is achieved for sensorfusion of an acoustic sensor with a differential pressure sensor, a watercut sensor and a differential temperature sensor. SINTEF has developed a filterbank HT ASIC for the downhole signal processing of acoustic data.
Autonomous Seabed Data Acquisition
Authors: MacDonald Alastair
Published: December 2007

Within the offshore industry there is growing demand for "faster, better, cheaper" offshore operations, and, whilst not compromising HSE issues, offshore operational parameters are getting ever tighter. The industry knows that only by a radical re-appraisal of traditional operational methodology will it be able to achieve its new objectives.

With the emergence of autonomous technology, the offshore industry is now being offered a new tool for offshore seabed exploration and surveying which meets its demands. After ten years of focused development, Maridan A/S of Denmark has now brought to market its M600 series of autonomous underwater vehicles (AUVs) and this technology is now achieving the industry’s desired operational improvements for offshore surveys. Maridan can safely say that the Maridan M600 AUV is proving its worth in the real world and this technology is no longer the subject of research projects or blue-sky developments. The key features of the Maridan M600 AUV includes: ModularityManeuverabilityNavigationReliabilityAutonomySingle Integrated Sensor suite
Offshore Gas-To-Solids Technology
Authors: Fitzgerald Antony , Taylor Mark
Published: December 2007

BG Group’s Hydrates Gas–to-Solids (GtS) technology has been established to investigate ways of managing gas in regions lacking suitable gas infrastructure and/or local markets. Put simply, the technology amounts to adding natural gas to water and stirring. This converts the gas into hydrate that is then shipped to market for regasification to supply power generation facilities or other gas customers.

The low complexity of this technology and the potential for small-scale modular operation is particularly appropriate for offshore associated gas applications where growing environmental pressures to reduce or eliminate gas flaring frequently create situations in which oil developments cannot proceed if there is no technical or economic means for gas disposal.

BG is progressing further pilot plant scale testing and engineering definition programmes with the aim of targeting a potential commercial plant operation by 2006.
Intelligent Well Technology in Mature Assets
Authors: Akram Navid , Hicking Steve , Blythe Paul , Kavanagh Peter , Reijnen Paul , Mathieson Derek
Published: December 2007

Sustainable growth in mature areas of the oil sector must continually focus on finding additional value often coupled with reducing lifecycle costs. New technologies promise much in realising these aims but must first be successfully implemented. Implementation of new technologies in mature areas often poses significant integration challenges, particularly with respect to existing field infrastructure.

The Northern Business Unit (NBU) of Shell U.K, operator in the U.K. sector of the North Sea for Shell and Esso, operates nine fields that produce 400 Mboepd oil and gas from both offshore platform and subsea facilities. Intelligent well technology, in particular downhole flow control, has been identified as having significant value adding potential for these fields.

The Interval Control Valve or ICV is the core component of a downhole flow control system and is a device analagous to traditional wireline operated sliding sleeves. The ICVs provide on-line remote control of the communication path from the reservoir zone to the production tubing. The devices can be either binary (open and close only) or variable (capable of some degree of choking).

For the mature assets the key value adding capabilities facilitated by the ICVs include the optimisation of oil production, the provision of zonal water management capability and the provision of more flexible cost-effective gas capacity management. In order to realise this potential a number of challenges in terms of integration with existing infrastructure, qualification of new equipment and operating philosophy had to be addressed.

Worked examples are presented for wells installed in the Brent and Tern fields highlighting where the intelligent well proposals add value, outlining the technical challenges and introducing the operating philosophies required to realise lifecycle value post-installation.
A Model-Based Approach to Assist Operation of a Gas-Constrained Multizone Intelligent Completion in the Ness Formation
Authors: van Delden R. M. , Uv E. H. , Jalali Y.
Published: December 2007

We examine the nearly one-year history of a horizontal well equipped with three downhole valves to control production of three presumably distinct sand channels of the Ness formation in the Oseberg field. We present a modeling methodology to assess the impact of downhole flow control on production performance, and explain how this methodology addresses the problems of zonal allocation and valve settings selection.
Implementation of Advanced Wellsite Data Management and Communications System Adds Value and Efficiency to Welltesting Operations
Authors: Pahmiyer Robert , Flowers Andrew , Almanza Edgar , El Assal Hossam
Published: December 2007

In the past, in order to carry out any type of real time analysis or control during a welltest, the subject matter expert had to be present at the wellsite. This paper will describe a recently developed real time operations (RTO) data acquisition and management system that uses advances in software operating systems, networking, telecommunications and Internet/intranet access to allow users to have access to real time data and information regardless of their locations. This type of real time access to well information allows expertise to be available that might not have been in the past due to distance constraints, and time and expense required to travel to the wellsite. It also allows real time collaboration from all individuals who have access to the data, regardless of their location, so that reservoir management decisions can be made quickly and more efficiently.

The system has been successfully deployed on a number of welltests in the deepwater Gulf of Mexico, offshore Egypt and onshore eastern Venezuela. An overview of the operations, which includes efficiency gains and time saved, will illustrate how controlled access to real time data and information via a local area network (LAN), a wide area network (WAN), an intranet, or the Internet can positively affect cost and efficiency by allowing state-of-the-art testing to be performed in remote areas where it previously might not have been possible or economically feasible using traditional testing systems.
Microbial Enhanced Oil Recovery: Diverse Successful Applications of Biotechnology in the Oil Field
Authors: Bailey S. A. , Kenney T. M. , Schneider D. R.
Published: December 2007

The field history and performance of microbial culture products for the oil field is examined. For over 15 years, microbial culture products have been used for paraffin control, production enhancement, well bore treatments as well as for scale and corrosion problems. The wide-ranging capacity of microbes to effect positive changes in oil and water properties is described. The broad spectrum of oil types and formations that have been treated successfully is reported along with treatment protocols. Mechanistic considerations for modes of action are analyzed. Traditionally, these considerations involve the continuous production of biosurfactants, solvents and other oil mobilizing agents.

Continuous advancement of microbial technology has led to more recent development of new applications that use unique metabolic capabilities of microorganisms to address specific well problems. Examples of applying these products to problems in oil field production systems are shown. The outlook for development of new technologies and the future application of these products to the oil field is discussed.
Use of Permanent Resistivity and Transient Pressure Measurement for Time-Lapse Saturation Mapping
Authors: Charara M. , Manin Y. , Bacquet C. , Delhomme J. P.
Published: December 2007

Optimization of hydrocarbon recovery requires information on the space and time behavior of the saturation of the various fluids present in the reservoir. This is particularly true for oilfields under secondary recovery such as water flooding, where an even reservoir sweep or zones of by-passed oil can be assessed by a proper description of the water front advance.Permanent downhole electrodes have recently successfully been deployed in oil wells.

This technology allows the time variation of the electrode potentials to be interpreted in terms of changes in saturation within the formation. In practice, the depth of investigation of such measurements is however limited. Time-lapse pressure transient is an independent source of information with a greater depth of investigation, therefore provides an adequate complement to the permanent resistivity array measurement.

In this paper, we propose to use pressure build-up from shut-in in association to the electrical measurements. After recalling analytical analogies in both types of measurements, we propose a quick-look method for interpreting the time-lapse pressure transients. We then compare the physical and practical advantages of each type of measurement and the domain of application of the two measurements with respect to fluid and reservoir properties. Finally we propose an example showing the benefit obtained by coupling the two techniques.
Jintan: Optimizing Field Development through Multi-Scenario Modelling
Authors: David Frank M. , Weesie H. B. M. Paul
Published: December 2007

A Multi-Scenario Modelling approach was used to select a field development option that is robust for most if not all of the sub-surface realisations. This approach was adopted for the Jintan carbonate gas field, located offshore Sarawak, Malaysia in the South-China Sea. The Jintan field will be developed as a satellite to the nearby M1 offshore gas production facility for the supply of gas to the MLNG Tiga plant, which is currently under construction. First gas is in July 2003. Significant value has been added through an integrated, multi-discipline sub-surface study which provides the basis for the field development plan: (1) cost savings of more than 60% were realised through integration of Jintan in Shell's existing gas infrastructure of Sarawak and by reducing the number of wells from 12 to 6, (2) the expectation initially-in-place volumes increased by approximately 1 Tscf to 4 Tscf of gas.

Key uncertainties for the Jintan field are gross rock volume (GRV) and porosity, permeability (tight streaks, karst and fault features), the initial pressure (due to possible depletion from the nearby producing fields) and the effective aquifer strength. The applied workflow to model these uncertainties included structural uncertainty modelling, stochastic inversion, static reservoir modelling and dynamic simulation.

The deliverable of the (Jason) stochastic inversion study were 93 combined depth/porosity models. Five of the 93 depth/ porosity models were selected for the final porosity modelling and exported to the 3D static reservoir simulation software. The static modelling resulted in 11 different static models, which were used for the dynamic modelling.

In the dynamic simulator, the initial pressure uncertainties were combined with the 11 static models into 33 sub-surface realisations which were then combined with different aquifer strengths and karst realisations. For each of the realisations an optimal development option was selected based on the currently expected capacity/offtake requirements and possible future changes/flexibility.

The resulting field development plan is robust for the following reasons: The selected development option caters for the uncertainty range of almost all modelled subsurface scenarios.Dependent on the subsurface scenario, 4 to 7 wells will be drilled. The exact number of wells required to provide a given capacity will be determined during the drilling phase.Well head compression is required in almost all scenarios but never within the first years therefore allowing sufficient time to monitor the reservoir performance and, if required, execute a compression project.

The described workflow, with a high level of integration between the subsurface disciplines, demonstrates the value of multi-scenario subsurface uncertainty modelling in situations where large uncertainties exist.
Underbalanced Coiled-Tubing Drilling in a Thin Gas Storage Reservoir: A Case Study
Authors: McCallister John V. , Haddad Kerima L. , Keenan Robert
Published: December 2007

This paper is a case study of a Coiled Tubing Drilling (CTD) project in which a lateral extension was drilled from an existing wellbore into a gas storage reservoir. The project took place in the Donegal Storage Field located in Southwestern Pennsylvania. The gas storage reservoir is the Gordon Stray Sandstone at a depth of approximately 2,680 feet true vertical depth (TVD) in the project well (Donegal #4621). The focus of this case study is on the geological and engineering considerations as part of pre-planning and candidate selection, drilling operations, problems encountered during the project, and the deliverability enhancement that was achieved.

The drilling of a lateral extension using CTD technology was considered as a method to improve deliverability for several reasons: the failure of previous attempts to stimulate wells in the field using conventional and unconventional methods, geological considerations (including the extremely limited reservoir thickness of approximately four feet), the wellbore configuration, and the reduced footprint (environmental impact).

Drilling operations used several technologies that are considered unconventional in the Appalachian Basin. Build rates and steering were controlled via an umbilical within the coiled tubing. The umbilical contained an electric line for the transmission of Logging While Drilling (LWD) data, and hydraulic lines to manipulate the direction of the bit. The well was also drilled in a constant state of underbalance using on-site generated nitrogen to reduce mud column weight and four-stage separation to control flow rates at the surface.

Although several problems were encountered, and are discussed at length in the body of this paper, the lateral extension on Donegal #4621 was successful. A 698 foot lateral was drilled with approximately 450 feet located in the storage reservoir. Initial testing indicates that the horizontal extension has yielded over an 8,000% increase in deliverability from this well.
Using an Expert System to Diagnose Formation Damage Mechanisms and Design Stimulation Treatments for Gas Storage Wells
Authors: Xiong Hongjie , Robinson Bradley M. , Foh Steve
Published: December 2007

In gas storage wells, many different types of formation damage can occur that dramatically curtail injection and withdrawal rates. Some of these damage mechanisms are similar to producing wells (mud/cement damage during drilling, completion problems, etc.); however, some types of damage are more specific to gas injection and storage (bacterial growth, contaminants, etc.). All these different damage mechanisms require different stimulation treatment methods and fluids to increase injectivity and deliverability. However, diagnosing the correct type of formation damage is not a simple task. The process requires gathering specific types of data and interpreting the results. Correct diagnosis of the actual damage mechanism(s) and design of the appropriate treatment requires expertise and experience.

Over the years, numerous studies have been performed on formation damage, and a vast amount of experience has been obtained on the design of stimulation methods and fluids to remove damage. However, this knowledge and experience is not always available or accessible to engineers dealing with stimulation design, especially with the unique types of problems associated with gas storage reservoirs.

This paper describes a comprehensive computer model designed for gas storage wells to help engineers diagnose formation damage and select the best stimulation treatment. The model combines domain knowledge bases with the best available expertise using fuzzy logic and expert system technologies. After diagnosing the most likely formation damage mechanism(s), based upon input data, the program will select the best treatment method and recommend treatment fluids and additives for the stimulation.