bluuebunny/crossref_metadata_2025 huggingface dataset:
Strategic Decision Making in the Upstream Oil and Gas Industry: Exploring Intuition and Analysis
Authors: Dinnie N. C , Fletcher A. J. P , Finch J. H
Published: December 2007

This paper reports on research examining established decisionmaking in the Upstream Oil and Gas Industry. Two important aspects of the strategic decision making process are high-lighted. The main emphasis is on exploring the often neglected intuitive (or non-analytical aspects) of the process although the analytical aspects will also be highlighted and both aspects will be considered in combination. As a means of comparison across companies, companies will then be grouped into different typologies based on the different emphases they place on the intuitive/ analytical aspects. Finally, a model of strategic decision making will be presented which integrates various aspects of the decision making processa. This research is based on analysing the information derived from fifty three face-to-face interviews with individuals working in the UKCS and in Australia who had knowledge of the strategic decision-making process. Eleven operators and one contractor were involved in the study. Initially, open-ended interviews were conducted and this was later followed by semi-structured in-depth interviews. A grounded theory approach was used to analyse the results. Ultimately, it is hoped that the research will be of interest to companies who wish to increase the transparency and their understanding of the strategic decision making process. It will also help companies both to recognise and accrue the valuable contribution of both intuition and analysis in strategic decision making. It is also suggested that although the intuitive aspects may be less visible and widely acknowledged due to their tacitness, difficulty in being codified and communicated, under certain ‘unique’ circumstances as evidenced by ‘intuitive decisions’ they may become more visible, codified and more easily articulated and shared.
A Method to Assess the Value of Intelligent Wells
Authors: Gai H.
Published: December 2007

This paper articulates the understanding of the value of the Intelligent Well (IW) technology, and presents a systematic method to quantify the value of IW technology in specific applications.

Assessing the value of a project is often a prerequisite for its start and success. Without a clear understanding of the potential value of the technology, progress would be haphazard at best. The status of the technology is discussed. It is argued that understanding the value is a key for the industry to decide where to take the IW technology, which in turn will govern where to take the industry in terms of value addition.

The attributes of value determine the level of complexity of the task. Some efforts are made to show that a myriad of factors both affect the value and prevent a reliable or even a meaningful assessment being carried out.

The method described is a collection of common sense approaches, leading to a recommendation for the applications, based on the value and other considerations. Step-by-step explanation is presented. An example is also given. It has been shown that rigorous value assessment for a specific project could lead to new insight into aspects that unstructured analysis may not provide. The option with the highest NPV may not be the one that is recommended.

The mechanisms used in the method are not limited to IW value assessment.
Slimhole Completion Experience in Java Sea, Indonesia: A Look Back on Performance of the First 40 Slimhole Wells
Authors: Susilo Yoliandri , Wibowo Wahju , Dewi Devialina P. , Dwibhakti Kristyawan
Published: December 2007

Slimhole completions have been applied worldwide for years. The aim of this type of completion is to reduce well costs (drilling and completion) and therefore improve project economics. This paper presents the results of applying slimhole completions into oil and gas wells in the Offshore North West Java (ONWJ) Field, Indonesia. In looking back at the performances of previous wells, this paper focuses on problems associated with slimhole wells during completion time and their post-production compared with potential cost savings and future well intervention benefits.

To date, more than 40 slimhole wells have been drilled in ONWJ fields. Typically, the wells were completed in 3-1/2" or 2-7/8" monobore. Cost savings were achieved through these completions. However, additional problems seem to have arisen during completion time that could reduce the economics of the project. The most frequent problem during completion was due to cement obstruction (22.2% from total cemented wells) in the liner section after the cementing job, caused by poor cement displacement. This commonly occurred on relatively deep and deviated wells. From previous experience, drilling practice has improved, resulting in fewer operational problems during completion time.

The overall results show the problems associated with slimhole are still within an acceptable range compared with the potential cost savings and benefits. In our case, production rates from slimhole-monobore wells have not been much different from conventional wells. This paper also shares some operational practice improvements made to reduce problems associated with slimhole-monobore wells.
Temperatures Induced by High Power Lasers: Effects on Reservoir Rock Strength and Mechanical Properties
Authors: Graves Ramona M. , Batarseh Samih , Parker Richard A. , Gahan Brian C.
Published: December 2007

The temperature effects of high power lasers on rock strength and mechanical properties are presented. It was found that the high temperature induced by lasers drilling through rock enhances porosity and permeability and reduces strength. High temperature causes microcracks, vaporizes cementation, and dehydrates clays.

Microcracks were monitored using thin sections and SEM analyses. Representative samples were cut for thin section analyses before and after lasing. For the SEM test, a small fragment of the sample was removed and coated with gold for better electron conductivity, thus allowing fracture imaging in three dimensions.

Phase changes also affect rock properties such as permeability, porosity and strength. The effect depends on the temperature distribution and gradient as well as the mineralogy. At each temperature, different reactions take place. For example, at 550°C smectite clay will collapse and dehydrate. This mechanism results in increasing void space in the rock sample. At the same temperature, quartz grains will expand by 1.75%1 and when the grains cool, microcracks are created, which also increases the void space. This increase in void space may or may not change permeability, but it does decrease the acoustic velocities that in turn change the calculated porosity and elastic moduli.

Results show in all cases, the Young's modulus, shear modulus, bulk modulus, and combined modulus near the lased portion, were reduced when compared to the unlased portion.

In sandstones, the decrease was 50% or more. A bulk modulus decreased of 50% causes the compressibility near the wellbore to increase by 50%. Depending on the lithology, Poisson's ratio decreased or increased slightly. For limestones and shales, the differences between the moduli of lased and unlased samples were less significant than in sandstone.
Ekofisk Field Well Log Decompaction
Authors: Gauer P. R. , Sylte J. E. , Nagel N. B.
Published: December 2007

The Ekofisk Field is a large oil reservoir located in the Norwegian sector of the North Sea. About 8.2 meters of seafloor subsidence has occurred above this thick, high porosity chalk reservoir since production started in 1971. The seafloor subsidence is a result of reservoir compaction in the chalk, driven primarily by pressure depletion early in the field life and water weakening at later stages.

Reservoir compaction monitoring via radioactive marker bullets has established a clear association between compaction and changes in water saturation and reservoir pressure. These data have also confirmed the mechanical behavior of the chalk observed during laboratory tests. The compaction of high porosity chalk is a result of both net effective stress increases linked to pore pressure depletion and water weakening induced by water injection. Field compaction data from a compaction monitoring well located in the crestal part of the field also suggest a vertical compaction to subsidence ratio of 1.20 to 1.25.

Owing to compaction-related issues, many wells have been redrilled over the life time of the field. The new wells have yielded new data, such as porosity, water saturation, and layer pressure, spanning the entire field production period. These data, however, have been affected by compaction and, consequently, have introduced biases when used as hard data to build a geological description of the reservoir. A porosity loss of as much as 10 p.u., for example, can be predicted for high porosity, crestal chalk which has undergone a total reservoir compaction approaching 40 feet over a 30-year production life.

More than 200 wells have been drilled since 1971 at Ekofisk, with only 42 of them being considered representative of the initial geological state of the field. In order to utilize the data from all 200-plus wells, a software program was developed to handle the complex decompaction and forward compaction logic needed to correct the well logs for compaction effects. Using the decompaction and forward compaction capabilities of the developed software, data from all 200-plus wells were used to evaluate the total reservoir compaction volume and shape. This was, in-turn, compared to 4D seismic-based compaction results as well as compaction results from geomechanical simulations.

The developed software and evaluations have made it possible to now build a geological model of the Ekofisk reservoir using data from the 200-plus wells drilled on the field, each representing the initial state of the reservoir prior to production in 1971. Ultimately, this is expected to improve the flow simulations of the reservoir leading to better estimates of production and reserves.
Probabilistic Analysis of Wellbore Stability During Drilling
Authors: de Fontoura Sergio A.B. , Holzberg Bruno B. , Teixeira Édson C. , Frydman Marcelo
Published: December 2007

The current paper presents three analytical methods for evaluating the influence of parameter uncertainties in the wellbore failure process: FOSM (First Order Second Moment), FORM (First Order Reliability Model) and SEAM (Statistical Error Analysis Method). Results generated by Monte Carlo method are used as reference. These methods evaluate the probability of failure based upon reliability indexes. The paper also presents the results of a sensitivity study to establish the most important parameters that control wellbore instability. This is necessary in order to limit the number of calculations before establishing the probability of failure. The results demonstrate the importance of reducing uncertainties associated with the relevant parameters by means of careful testing procedures.
Using Flow Induced Stresses for Steering of Injection Fractures
Authors: Jørgensen Ole
Published: December 2007

Both horizontal and vertical rock stress magnitudes are substantially affected by pore pressure gradients generated by production from and water injection into low permeable chalk fields. This is confirmed by solid mechanics stress analyses and by observing fracture propagation in developed fields. Stress changes generated around horizontal injectors placed centrally between two parallel horizontal producers are considered in detail in this paper. It is shown that overburden and sideburden stresses may be altered and controlled to confine propagation of fracturing along the length of a central openhole horizontal injection well. It thereby becomes possible to establish a line drive development based on injection of water at fracturing conditions at reduced risk of premature water breakthrough (patent pending).
Estimating Fluid Pressures That Can Induce Reservoir Failure During Hydrocarbon Depletion
Authors: Streit J. E. , Hillis R. R.
Published: December 2007

A Mohr-Coulomb failure criterion is applied to estimate fluid pressures that may cause fault reactivation during the depletion of hydrocarbon reservoirs. The estimates incorporate the decline in total minimum horizontal stress that accompanies fluid pressure depletion in hydrocarbon reservoirs. Such pore pressure/stress coupling must be incorporated in predictions of depletion-induced failure because it significantly influences the fluid pressures at which faulting occurs. A new algorithm for failure incorporating the coupled decrease in pore pressure and stress is derived to calculate the fluid pressures that can cause slip on normal faults during ongoing production. The algorithm is applied to the Ekofisk reservoir, Norway, using various friction coefficients for chalk and incorporating the observation that the minimum horizontal stress decreased at 80% the rate of pore pressure depletion in the field. A friction coefficient of 0.6 yields realistic results when modelling the depletion period 1975 to 1990. A fluid pressure decrease from the initial 45 MPa to 38 MPa is required to activate optimally oriented faults with dip angles of approximately 60°. This fluid pressure level (38 MPa) was attained in 1978-1980 and marks the onset of significant subsidence in the Ekofisk field. Ongoing fluid pressure depletion from 38 MPa to the present level of approximately 25 MPa is sufficient for sliding on faults with dip angles of 48° to 73°. Preexisting fractures in the Ekofisk reservoir fall in this range, as they exhibit predominantly steep dip angles (65°). Slip events recorded during seismic monitoring that was conducted in 1994, are likely to represent the reactivation of such steeply dipping faults and possibly the formation of new fractures. The modelling technique presented for predicting induced reservoir and fault failure is an essential requirement for the long-term planning of hydrocarbon field depletion.
Evaluating Stress-Induced Anisotropy and Mechanical Damage From Cross-Dipole Sonic Data Using Dispersion Analysis
Authors: Plona T. J. , Kane M. R. , Sinha B. , Walsh J.
Published: December 2007

Advanced sonic characterization of near-wellbore mechanical damage and formation anisotropy yields important new information for drilling and completion engineering as well as for geophysics. Damage in shales is a precursor to wellbore stability problems. Stress-induced mechanical damage in weak reservoirs indicates zones where selective vertical perforation can reduce the risk of sanding. Identifying stress-induced anisotropy enables orienting perforations consistent with the stress direction to minimize sanding problems and optimize production; and in the case of hydraulic fracturing, to minimize near-wellbore tortuosity. Proper well placement to maximize oil recovery from hydrofracing requires knowledge of the stress directions.

Sonic cross-dipole logging with advanced frequency-domain processing provides the unique capability to characterize the mechanical state of the formation around the borehole. Traditional processing is performed in the time domain and identifies whether the formation is isotropic or anisotropic. Recently, we showed that frequency-domain processing of cross-dipole data (i.e., slowness-frequency analysis or dispersion analysis) distinguishes intrinsic from stress-induced anisotropy. The unique identification of stress-induced anisotropy also yields the stress direction. Further processing can lead to estimates of stress magnitudes. These results are obtained even in the absence of breakouts or drilling-induced fracturing, the traditional borehole stress indicators.

The near-wellbore region can be significantly perturbed by the drilling process and the associated borehole stress concentrations, resulting in radial variation of the shear slowness. Slowness-frequency analysis of cross-dipole data shows that low frequencies sample at a distance into the formation that is equal to two to three borehole diameters, sensing the unaltered rock. High frequencies penetrate a distance equal to one borehole radius, probing the mechanically damaged zone. Deviation from the homogeneous model at high frequencies indicates damage. Analysis of dipole dispersion curves yields an estimate of the depth of the mechanical damaged zone.

Worldwide (Middle East, Africa, Gulf of Mexico, Southeast Asia) field examples in both overburden shales and reservoir rocks (sands and carbonates) highlight the additional information derived from cross-dipole dispersion curves. Dispersion analysis of these data sets enables identification of: 1) stress-induced anisotropy, stress direction, and stress magnitudes; and 2) near-wellbore mechanical damage in both sands and shales.

The key to this new understanding is the combination of wide-band acquisition of crossed dipole sonic data, advanced frequency-domain processing techniques, and good knowledge of acoustic wave propagation in boreholes.
Dual-porosity Approach for Directional Boreholes
Authors: Zhang Jincai , Roegiers Jean-Claude
Published: December 2007

Naturally fractured reservoirs can be treated as dual-porosity media consisting of a primary rock matrix system as well as fractures. These dual-porosity formulations coupling matrix and fracture deformations as well as fluid flow in both systems are first presented. The finite element solution for any directional wellbore drilled in a dual-porosity medium is given. Mud weight considerations are presented for both permeable and impermeable boundary conditions. A case study for inclined wellbore problems was also conducted. The effects of single- and dual-porosity, time, and mud weight are parametrically studied allowing for a better understanding of the physical characteristics governing borehole problems.
Uncertainties in the Pore Pressure Evaluation in Deepwater: a Statistical Approach
Authors: Falcao José L.
Published: December 2007

The Pore Pressure is a critical point of any drilling project, once it influences the definition of the mud weight, casing setting depths, casing design, riser safety margin (RSM), etc. During the design stage of offshore and shallow water wells, safety factors (ranging normally from 0.5 to 1.0 ppg) are introduced to compensate the lack of accuracy in pore pressure evaluation. However, this may impose a limit in deepwater drilling operations. In such environment, as the water depth increases, the formations tend to show lower fracture gradients, which makes the difference between the pore pressure and the fracture gradient curves quite small, complicating the project.

In this work the methods employed by Petrobras to evaluate the formation pressure are reviewed. Next, a procedure, employing statistical analysis, to evaluate the uncertainty in the pore pressure determination in the offshore portion of Campos Basin - Brazil, is presented. For that, a DST (drill stem test) and RFT (repeat formation test) database collected along the years in this area is employed. As a result, the safety factor applied over the Pore Pressure could be reduced, simplifying deepwater well projects.
A New High-Resolution Electronic Memory Gauge Improves Reservoir Characterization
Authors: Azari M. , Kool H. , Soliman M. Y.
Published: December 2007

A new quartz electronic memory gauge that has been introduced to the oil industry will be presented in this paper. This gauge can record data with more precision than existing gauges, and thus, can establish more accurate flowing and shut-in pressure with higher resolution. In addition to describing the gauge design, this paper will also discuss the advantages of improved gauge resolution in the analysis of well test data and in determination of the hydrocarbons in place. The impact of using a higher resolution gauge on well testing is illustrated through analysis of field data.
Field Trial of a Downhole, Fiber Optic, Two-phase Flowmeter in PDO's Nimr Field
Authors: Kragas Tor K. , van der Spek Alex , Al Hashmi Khalid M.
Published: December 2007

A field trial was conducted in June, 2001, of a downhole fiber optic two-phase flowmeter in two wells at PDO's Nimr field in Oman. The fiber optic flowmeter provides real-time measurements of volumetric flow rate and water cut. The purpose of the field trial was to evaluate the performance of the flowmeter for potential application at Nimr. Specifically, objectives were to determine the deployability of the flowmeter at Nimr, to determine the ability to operate with heavy, viscous Nimr crude, and to determine the ability of the flowmeter to distinguish between high water cut legs in dual lateral completions with artificial lift. Accuracy goals for the flowmeter were ±3% on water cut and ±10% on total volumetric flow rate.

The fiber optic flowmeter was successfully installed in two wells at Nimr. In one of the wells the meter was installed in the completion string just below an electrical submersible pump (ESP) and in the other well it was installed just below a beam pump. A surface Coriolis mass flow meter served as a reference for the two-week field trial. In the beam-pumped well it was found the noise environment is not compatible with the physical measurement principle of the optical flowmeter, and a comparison against the surface-measured rates was not possible. In the ESP-pumped well, comparison of the flow rates and water cut measured by the fiber optic flowmeter and the Coriolis meter were better than expected, -1% to +2% on water cut and -1% to +3% on total rate, and well within specifications.
Application of Silicone Microemulsion for Restriction of Water Production in Gas Wells
Authors: Lakatos I. , Tóth J. , Lakatos-Szabó J. , Kosztin B. , Palásthy Gy. , Wöltje H.
Published: December 2007

A novel method based on injection of silicone microemulsion was developed for restriction of water production in gas wells. The treating solution was a surfactant stabilized siloxane emulsion which was driven into the formation by water and nitrogen. According to the laboratory studies disproportional permeability modification is in the background of the water retention. The phenomena is attributed to inversion of microemulsion to macroemulsion initiated by spontaneous dilution by water and then entrapping of formed siloxane droplets by the pores. The method was tested at the largest Hungarian gas field (Algyő field, Hungary). Evaluation of the pilot test has definitely proved the beneficial effect of silicone injection on gas production and gas/water ratio: the gas production tripled and lasted for at least a half year. The encouraging results urged the operator to continue both the laboratory and the field tests with the aim at developing a method which might be used routinely in low permeable, tough gas fields and underground gas storage.
New One-Trip Multi-Zone Frac Pack System with Positive Positioning
Authors: Vickery E. Harold , Bayne Christian F.
Published: December 2007

Effective fracture stimulation of multiple pay zones usually requires multiple fracture treatments with multiple trips in and out of the wellbore for perforating and placing frac pack equipment. An additional concern is positive positioning of downhole equipment, particularly when performing high-pressure treatments in deviated wellbores or from a floating platform or drilling rig.

A system is presented that allows stimulation of multiple pay intervals using several independent fracture treatments to be accomplished with a single trip into the wellbore to place packers, screens and gravel pack tools. The system also keeps the equipment in proper positioning for each treatment, thereby minimizing the risks associated with treating multiple zones.

Treatment parameters are discussed to assist in designing the independent stimulations. We will also discuss several equipment issues important to eliminating risk associated with pumping these treatments.

An example is presented to illustrate how this system can be used to treat a long production interval with high laminated sands.
Detection of Asphaltenes Flocculation Onset in a Gas Condensate System
Authors: Thou S. , Ruthammer G. , Potsch K.
Published: December 2007

Asphaltene plugging is one of the most frequent causes of production depletion in medium and light crude oil reservoirs, especially when the pressure declines due to its exploitation. Other physicochemical phenomena, like intrinsic instability of the produced crude oil, incompatibility between "commingled" produced oils, between streams entering the flow stations, as well as inadequate stimulation procedure, can be responsible for asphaltene deposition during crude oil production and transportation, going from the reservoir to surface facilities.

Asphaltenes precipitation is one of the major operational problems affecting production in the Höflein field northwest Vienna. The deposits were responsible for plugging the coalescing filters, which are designed to dehydrate down to 5 ppm of suspended water. Asphaltene deposition is also blamed for prolonging the annual summer stopover, which is proposed for general maintenance on Korneuburg facilities.

The purpose of this work is to show the application of a systematic technique for detecting the onset of asphaltene flocculation under various pressure and temperature conditions as well as for selection and evaluation of chemical inhibitors in the field Höflein. The results allowed defining the asphaltene deposition envelope (ADE) as well as selecting the best inhibitor evaluated under production facility conditions. In addition, the characteristics of this phenomenon as well as the problems associated with it have been highlighted.
Fiber-Enhanced Visco-Elastic Surfactant Fracturing Enables Cost-Effective Screenless Sand Control
Authors: Heitmann Norbert , Pitoni Enzo , Ripa Giuseppe , England Kevin
Published: December 2007

Many gas reservoirs in the Adriatic Sea, offshore Italy, are formed of laminated, low permeability dirty sandstones, requiring gravel packing for sand control. Numerous gravel-packed wells are either sanded up and shut in, or are underperforming due to fines plugged gravel-pack screens, which cannot currently justify the expense of an immediate and cost-prohibitive full rig workover. Frac and packs are performed to increase productivity bypassing near wellbore damage, interconnecting multiple sandstone layers and decreasing fluid velocities in the formation, thus reducing fines production. Significant interest exists to enhance fracture performance, deferring and reducing re-completion costs.

This paper discusses various rigless performed rehabilitations of failed sand control completions, highlighting the evolution of fracture fluid selection, optimization of the fracture placement and achieved geometries with seawater-based visco-elastic surfactant fluids and the use of speciality glass fibers for fracture pack stabilization and enhanced proppant transport. This combined rehabilitation technique enabled screenless sand control completion and is allowing low cost rehabilitation of plugged or failed sand screens and the development of any numbers of gas layers which otherwise could not be drained using conventional sand control technologies. This completion technology potentially allows to significantly adding gas or oil reserves, the development of the normally by-passed upper gas layers, which would require costly workover re-completion using conventional technologies.

Procedures, experiences and results are presented, validating the -enhanced visco-elastic surfactant fracturing concept enabling screenless sandface completion for controlling sand production. Rigless rehabilitation has confirmed being an efficient solution and allows cost-effective production increase.
Reliable Wax Predictions for Flow Assurance
Authors: Coutinho João A. P. , Edmonds Beryl , Moorwood Tony , Szczepanski Richard , Zhang Xiaohong
Published: December 2007

A number of wax models are currently in use by the oil industry which are based on parameters that were empirically determined to match available data for black oils. These data are often not very precise. The recently developed model of Coutinho is, however, based on high accuracy thermodynamic data.

The paper describes how the Coutinho model can be used in conjunction with conventional equations of state to perform wax equilibrium calculations for black oils. Examples are given showing how well the model can predict both wax appearance temperature and the amount of wax precipitated at varying temperatures with or without n-paraffin analyses. The examples include the effect of pressure on live oils.

Improved thermodynamic modelling of wax formation in turn allows better prediction of wax deposition rates for flow assurance.
A Stepwise Example of Real Options Analysis of a Production Enhancement Project
Authors: Bailey William , Mun Johnathan , Couët Benoît
Published: December 2007

Practical solution to a Real Options analysis of a somewhat generic production enhancement problem is presented. First the problem is properly framed, suitable data is gathered, the analysis is performed and finally the results are communicated. Ancillary issues concerning the most appropriate solution methodology and the quantification of a representative volatility component are also touched upon. The narrative is constructed in such a way as to, hopefully, enable usage beyond the specifics of the problem discussed. A form of visual representation of results is proposed that may facilitate communication, improve understanding and help gain acceptance of the benefits of such an analysis from management and decision-makers’ points of view.
Improving Team Capability and Efficiency by Moving Traditional Rig-Site Services Onshore
Authors: Wahlen M. , Sawaryn S. , Smith R. , Blaasmo M.
Published: December 2007

The continuous improvements in high-speed communications and information technology are transforming traditional drilling working practices. For some services such as data and LWD engineering, personnel no longer need to be physically present at the rig site. New technology guarantees their virtual presence. Instead, these positions can be moved onshore, adding to the overall team capability and efficiency. At the same time, this reduces the over all HSE exposure and offers further potential savings in bedspace and transportation costs. To effect this transition, each of people, process and technology challenges have had to be addressed. These concepts have been embodied in the "Baker Expert Advisory Center/Operations Network" (BEACON) system, established in Stavanger, Norway.

The paper describes the challenges faced in establishing the system and their solutions. Human factors are shown to play a crucial role in its successful implementation, demanding greater flexibility in onshore working practices to match those remaining offshore and to establish the virtual team. During the initial trial period, these factors, compounded by reliability and maintenance problems caused the system's operation to be suspended. Following a review, operations were restarted and two wells have now been successfully drilled in this operational mode. Improvement in the team's decision-making capability is evident and has been described as "increasing the team IQ". Improved access to the onshore centre, compared with offshore, is now shown to increase reliability and flexibility. Finally, the paper summarises the future work planned under the Norwegian Demo2000 sponsorship program, which will address the provision of these services in more formal terms.
Field Evaluation of Iron Hydroxide Gel Treatments
Authors: Kosztin B. , Palásthy Gy. , Udvari F. , Benedek L. , Lakatos I. , Lakatos-Szabó J.
Published: December 2007

A novel gel treatment technique based on transformation of water soluble Fe(III) compounds into gel-like precipitate by in-situ hydrolysis and flocculation was developed for water shut-off in mature oil fields. The new blocking material has excellent stability under field conditions, and yet simple remediation is possible in case of placement failures. Further, the novel method is characterized by self-controlling chemical mechanism and using this technique injectivity problems didn't arise even in low-permeability and tough formations.

The extensive field program was supported with special software determining the penetration distance from the wellbore. Based on log data, the pay zone was subdivided into a maximum of four layers assuming that crossflow among zones was negligible. Total volume of the treating fluids was obtained by asserting two limiting rules: the treating fluid must reach a minimum penetration depth (>15 m) in the layer having the highest permeability, but the max. penetration depth should not exceed 2 m in the layer having lowest permeability.

The test program comprised treatment of ten oil producing wells and seven water injectors. The well responses varied between wide limits: technical success was achieved in about 60 % of the wells, and the treatment was economically beneficial in about 40 % of the cases. In special reservoir blocks the injector wells were simultaneously treated with the oil wells. The primary goal of this project was to enhance the effect of flow profile correction around the producers and to improve the frontal displacement mechanism. The new method was compatible with the dirty sandstone reservoir systems, and there were no technical failures. The positive results contributed significantly to the operator's decision to extend use of the new method to other reservoirs.
Simplified Prediction of Reservoir Pressure in Coalbed Methane Wells
Authors: Cooper Joshua E.
Published: December 2007

Prudent coalbed methane (CBM) reservoir management and optimization requires knowledge of reservoir pressure. This paper presents a simple three-step method to predict reservoir pressure throughout the producing life of a coalbed methane well using only initial reservoir pressure, Langmuir pressure and cumulative gas produced. Use of the method has the potential to significantly reduce operating costs by minimizing the number of pressure surveys required to understand, operate and optimize a well or reservoir. The equations and process used to predict reservoir pressure are discussed, results of simulation studies validating the method are presented and actual examples from Fruitland Coal wells in the San Juan Basin are used to test the applicability of the method to real world conditions.
A New and Robust Simulation Model for Coalbed Methane Reservoir
Authors: Jan Badrul M. , Siagian Ucok W. , Lee Robert L. , Othman Roslee
Published: December 2007

A new and robust approach was developed to simulate flow of methane gas in coalbed methane reservoirs. The proposed simulation model was developed for a 2-phase, 3-dimension, single porosity with desorption/adsorption phenomena. The model was developed based on mass balance concept and control volume approach. Flow of gas in the fracture is modeled by Darcy's Law, while movement of gas in the coal matrix is assumed to obey diffusive process. A new equilibrium equation is proposed to represent the process. To verify the developed model, we history matched Well # 1, an active gas well over a period of about 4 years. The well was producing from Fruitland formation in San Juan Basin, northwest of New Mexico. In addition, we also made prediction study of Well # 1 in which we investigated the effect of completion techniques (vertical vs. horizontal), fracture and stress sensitive permeability on the overall performance of Well # 1. The results of the study indicate that the developed model is able to predict the performance of a coalbed methane reservoir quite well. The model behaves as predicted and it closely matches the past performance of Well #1. The results also highlight the importance of stress sensitive permeability consideration in coalbed methane evaluation even in low fairway area of San Juan Basin where permeability is less than 1.0 md. Neglecting the effect may result in overestimation of reservoir performance. The study also suggests that fracturing job might be a crucial element to prevent Well # 1 from being shut down prematurely.
Medina Stimulation: Is Bigger Really Better?
Authors: Fontaine Jim , Paugh Len , Watson Jim
Published: December 2007

Over the past thirty years, the Medina sandstones have been the primary drilling target in northwestern Pennsylvania. Numerous operators have drilled and completed thousands of wells in this tight gas sandstone. As fracturing technology has evolved, many different types of treatments have been utilized; from "slickwater" fracs containing small volumes of sand pumped at low densities, to crosslinked gels carrying high volumes and densities of sand, to linear gels with widely differing sand volumes and densities, to nitrogen foams also transporting varying volumes and densities. While everyone agrees that Medina wells need to be stimulated in order to be productive, there are as many opinions as to the most successful technique as there have been operators. Often, these opinions are based upon conjecture with no comparative supporting data.

The Cramerven/Cooperstown field located in Crawford, Mercer, and Venango Counties provides an opportunity to review the history of Medina stimulation as well as compare the results of different frac styles. Wells in this field have been extensively analyzed and production tracked in order to determine the optimal stimulation technique. Although variability due to geologic differences can greatly affect the results of individual wells, large populations of wells have been compared in order to minimize the effect of this variability.

This paper will present a discussion of the historical stimulations performed in this field, compare stimulation design to Estimated Ultimate Reserves, provide background on the design and development of the treatments utilized, and finally, present an analysis of the current design based upon production decline analysis.
Automation of Casing Plungers for Increased Production
Authors: Gregg David
Published: December 2007

This paper will review the concept, use and current developments of casing plungers since their inception in the 1980's. Their use has only recently become a significant impact in artificial lift for producers.

The use of Casing plungers as a production tool in the USA has been developing for over 10 years. They have enjoyed a limited success as a valid production tool and are very specific in application.

Their success has been limited by some practices used during completion of a well and the internal conditions of the casing in older wells. There use in strings of casing with mixed weights has been erratic. Yet, the plunger has shown some very significant results in the production of gas from some very difficult wells.

The wells that have been able to apply this method of artificial lift, once found that the safe use of the casing plunger with its positive seals to be a prime issue when the plunger is in travel to the surface.

This includes the integrity of the casing with no damage to its interior walls. The use of varied weights of casing in a well string can also be an issue of concern.

The manufacturers of the casing plunger systems have limited the travel rate or velocity of the casing plunger by connecting the flow line to a tightly restricted orifice. This restricted flow has led to criticism of the production results that can be expected. The need for change of this design has led to a more successful operation.

There had been few developments in this equipment until the past few years. An effort to improve the production of the well with assuring a safe operation has led to a effort to design and develop a system that will yield optimal results.

The goals to develop an automated control system for the casing plunger were established. There had to be a Fail-safe control system that permits the production of a well in excess of what was possible with the current system.

It should create a longer life expectancy of the polymer seals that are affected by casing plungers cycling too often. The use of a free cycle plunger was dismissed as non-productive due to excessive wear on seals and dry runs.

The system should maintain higher production rates when the casing plunger is at surface. The seals should have a chance to stay in a low pressure lubricator to normalize.

All of these goals were to be a high priority in redesigning this system.
Mature Waterfloods Renew Oil Production by Alkaline-Surfactant-Polymer Flooding
Authors: Wyatt Kon , Pitts Malcolm J. , Surkalo Harry
Published: December 2007

The Illinois and Appalachian Basins contain many mature and economically marginal waterfloods. These fields produce at high water-oil ratios that have proportional fluid handling costs. Approximately 60% of the oil resource remains in the reservoir rock at these conditions. The Alkaline-Surfactant-Polymer, ASP, technology has been field demonstrated to recover 15% OOIP to 30% OOIP of this residual oil by minimizing capillary forces which trap oil, improving areal and vertical contact efficiency, and mobility ratio. Mechanisms of ASP flooding are discussed and field performance is compared with micellar technologies that were tested in the Illinois Basin.
Fundamentals of Developing a Surveillance Logging Quality Assurance and Quality Control Plan
Authors: Newman Mark A. , Hetznecker Paul F.
Published: December 2007

Developing a quality assurance and quality control (QA/QC) plan is an important element of any surveillance logging program. A QA/QC plan is used to document how quality assurance (QA) and quality control (QC) activities will be implemented during a program, project, or task1. A QA/QC Plan for a surveillance logging program can provide adequate and accurate information in assessing the level of pipe defects reported from casing inspection logs and can be used to record possible trends regarding the individual casing inspection tools. It may also analyze data to characterize errors in measuring tubular thickness as well as monitor tool accuracy and data interpretation.
Reservoir Modeling for Horizontal Exploitation of a Giant Heavy Oil Field - Challenges and Lessons Learned
Authors: Tankersley T. H. , Waite M. W.
Published: December 2007

The Hamaca Field, located in Venezuela’s Orinoco Heavy Oil Belt, is a giant extra-heavy oil accumulation operated by Ameriven, an operating agent company for PDVSA, Phillips and ChevronTexaco. Over the 35-year life of the field, more than one thousand horizontal laterals are planned in order to deliver 190,000 BOPD to a heavy-oil upgrader facility. Reservoir models are built to support a broad continuum of activities in order to meet this objective. This paper will review the Hamaca reservoir modeling process, the challenge of integrating many sources of geologic and geophysical constraints including horizontal well information, the focus on continuous model improvement, and issues unique to Hamaca rock and fluid properties.
New Solutions for Well Test Analysis of Horizontal Wells
Authors: Lu J. , Cunha L. B. , Lu T.
Published: December 2007

Horizontal wells are becoming popular for primary and enhanced oil recovery operations because of unique advantages of horizontal wells in comparison to those for vertical wells. For example, horizontal wells are being used, at present, for the primary recovery of heavy oil worldwide. They allow a larger reservoir exposure, which increases productivity, accelerate recovery, and reduce coning tendencies. However, horizontal well testing is considerably more complex than vertical well testing.

This work addresses new solutions for well test analysis of horizontal wells. With the similar methods in Ref. [1,2,3], taking a horizontal well as a uniform line sink in three dimensional space, by developing necessary mathematical analysis, this paper presents horizontal wells pressure drawdown and buildup analyses in a single porosity reservoir with a circular cylinder drainage volume.

The solutions obtained here which are based on three dimensional models are more accurate than the two dimensional model based well testing equations in the literature. Simplified solutions for short and long times that exhibit straight-line sections when pressure is plotted vs. time are presented. Methods for analyzing pressure drawdown and build-up data are presented. The method allows reservoir characteristics, including permeability, skin to be determined.
Horizontal Wells in Thermal Applications for Displacement and Gravity Drainage
Authors: Terez Ivan E. , Ehlig-Economides Christine
Published: December 2007

Reservoir simulation of injection and production well geometries for parallel horizontal wells with varied steam injection schedules was used to investigate recovery from primary production, displacement and gravity drainage processes. This revealed that the recovery following primary depletion is improved by placing the injector close to the top of the formation and the producer near the bottom. Once the steam chamber between injector and producer is formed and continuous, the gravity drainage mechanism becomes dominant. This regime is described as SAGD and the oil production is insensitive to steam injection rate.

The utilization of all three recovery stages results in 22-56% recovery with cumulative SOR of 4-5. The economic analysis (sensitive to specific oil/steam prices and discount factor) revealed that following primary depletion with the low rate drainage processes (SAGD) provided no increase in NPV over continuing primary production until the economic limit is reached. Following primary depletion with a higher rate displacement process on the original pattern or smaller pattern areas increased the NPV significantly.
Heavy Oil Carbonate: Primary Production in Cuba
Authors: Smith G. E. , Hurlburt G. , Li V. P.
Published: December 2007

Primary production has been carried out for more than 30 years from large overthrusted carbonate structures along the north coast of Cuba between Havana and Varadero. Long reach horizontal wells, with open hole completions, are used and extensive logging suites, including FMI, have been collected and analyzed. A huge amount of oil is held within the tight matrix but currently most of the produced oil is likely from macro and micro fractures, and breccia or vuggy porosity. It is postulated that primary production is supported by secondary gas in the fractures and "foamy oil". The EXODUS simulator has been used to model the system in dual porosity mode demonstrating the coning of gas and water in the fracture system and production from a "rim" of oil in the fractures at the level of the wells. Field observations and well performance also demonstrate the presence of gas in the fracture system and the high permeability necessary to drain the viscous oil.
Steam Conformance Along Horizontal Wells at Cold Lake
Authors: Smith R. J. , Perepelecta K. R.
Published: December 2007

This paper describes Imperial Oil’s success in identifying and remediating poor steam conformance in a horizontal well used in Cyclic Steam Stimulation operations.

Imperial Oil is conducting Horizontal Well Cyclic Steam Stimulation (HWCSS) at nine horizontal wells located at two pads in Cold Lake. Steam conformance along horizontal wells is a significant issue in these types of thermal applications. The horizontal wells are completed with Limited Entry Perforations (LEP) to improve distribution of steam along the liner. One of the HWCSS pads, D36, has been the subject of both 4D seismic and injectivity analyses to characterize steam conformance along the horizontal section over the first three cycles. These analysis techniques showed that four out of the five wells on the pad had excellent steam distribution along the horizontal liners. However, one of the wells, D36-H1 showed little or no steam conformance along the last half of the liner. This lack of horizontal steam conformance put the recovery expectations of this well at risk. A workover conducted on D36-H1 successfully removed sand that had been obstructing the liner. Steam injection subsequent to the clean out showed steam distributed across the majority of the liner (most of the LEPs accepting steam).