bluuebunny/crossref_metadata_2025 huggingface dataset:
Estimating Fracture Permeability and Shape Factor by Use of Image Log Data in Welltest Analysis
Authors: Bahrami Hassan , Siavoshi Jamal , Esmaili Soodabeh , Karimi Mohammad Hussein , Bahraie Ramin
Published: October 2008

The identification of fractures is essential during exploration, drilling and well completion of naturally fractured reservoirs since they have a significant impact on flow contribution. There are different methods to characterize these systems based on formation properties and fluid flow behaviour such as logging and testing. Pressure-transient testing has long been recognized as a reservoir characterization tool. Although welltest analysis is a recommended technique for fracture evaluation, but its use is still not well understood.

Analysis of pressure transient data provides dynamic reservoir properties such as average permeability, fracture storativity and fracture conductivity. An infusion of geological knowledge helps reducing uncertainty associated with any well-test interpretation. The static properties of naturally fractured reservoirs such as fracture distribution, fracture aperture, matrix block size and fracture porosity can be obtained from processing of Image Log data.

Simulation of naturally fractured reservoirs needs defining fracture permeability, shape factor and fracture porosity in the fracture model. However, in most simulation studies, due to high uncertainties in estimating fracture permeability and shape factor values, these parameters are initially assumed in the model and they are usually tuned during history matching which can be time consuming and also affect other history match parameters. Reservoir simulation results and predictions might be inaccurate if the values of fracture properties in the model are not reliable.

This paper shows using image log data associated with welltest analysis in order to determine dynamic fracture parameters such as fracture permeability and shape factor for reservoir simulation. In this study, sensitivity analysis has also been performed on fracture permeability, fracture porosity and matrix block size in real simulation models in order to show importance of accurate determination of fracture parameters.
Optimal BHA Design for Steerability and Stability with Configurable Rotary-Steerable System
Authors: Sugiura Junichi
Published: October 2008

There have been significant attempts to optimize the various bottom-hole assemblies (BHAs) used in rotary steerable (RS) applications because the optimal RS assembly can provide operators with significant cost savings by providing less vibration, high BHA stability, high-quality borehole, and thus predictable steerability.

This paper presents the development of BHA analysis models using simplified mathematical equations. RS BHA optimization process is demonstrated through the extensive field test program. The predictions of BHA response and directional drilling performance of the RSS have been examined with the numerous field test data taken in a controlled and non-commercial environment, allowing single step changes in both the drill bit features and RS configurations.

The testing is unique since the specific rotary-steerable system (RSS) works in field-configurable point-the-bit and push-the-bit modes. Between two distinct RSS operation modes, consistency in stiffness, weight, force applying capability, and control system lead to a direct comparison of different BHA models. Confidential test sites were selected for evaluating different RS BHA configurations in both push-the-bit and point-the-bit modes. The systematic BHA testing was conducted in two different test facilities in North America.

A unique sensor system, integrated into the specific RSS, provided real-time measurement of near-bit borehole caliper and near-bit stick-slip and vibration1,2 This feature allowed real-time evaluation of bit and BHA stability and borehole quality while the maximum build-up test was performed. After each test run, memory data was retrieved and used for more detailed assessment of bit and BHA performance.

BHA configuration tests were systematically conducted in a controlled environment so that the relationship between BHA analysis models and actual BHA behaviors could be identified. As a result, the systematic testing and verification lead to the optimal RS BHA design in both push-the-bit and point-the-bit configurations for stability, steerability and borehole quality.
Placing Two Fractures Consecutively in Close Proximity to Significantly Increase Revenue-to-Cost Ratio
Authors: Surjaatmadja Jim B.
Published: October 2008

Though fractures caused by stimulation will likely propagate away from high-permeability areas, the stimulation often provides a significant production improvement because of the large flow-path increase created by the fracture. This fact can be hard for many to accept. Placing two fractures consecutively in close proximity to each other may offer a tremendous benefit. With this approach, the first fracture is placed conventionally into the maximum stress direction. After a short delay, the second fracture is then placed, taking advantage of the temporary stress modification caused by the opening of the first fracture.

This delay is computed so the stress modification at the tip of the second fracture is always maximized. This is done so that the second fracture will extend into the original (natural) minimum stress direction, meaning the fracture will extend into highly permeable areas and, therefore, production expectations from the second fracture will potentially be much larger than production of the first fracture. This leads to a significant increase in the revenue-to-cost ratio. In other words, a significant revenue increase can be achieved with an incremental cost increase.

This new approach uses conventional pin-point stimulation methods; therefore, even though it is "new," it carries a very minimal risk with a potentially large payout. This paper discusses how the new process can be effectively performed by harnessing a pseudo-Maxwell/Kelvin-Voigt, creep phenomenon that is normally present in rock. The paper will also examine formation geology, reservoir aspects, best practices, better completion schemes, simulation data, and different stimulation and perforating techniques that would be best used for achieving maximum productivity.
Successful Open Hole Smart Completion, Case History from Saudi Arabia
Authors: Al-Amri Khalifah M. , Al-Nassir Abdulmohsin A. , Zhou Shaohua
Published: October 2008

Over the last several years Saudi Aramco embarked on a technology driven strategy to maximize well productivity and total oil recovery by converting existing weak horizontal producers or dead vertical wells to MRC (maximum reservoir contact) wells. Another application is drilling new MRC wells from surface, many of which, if required by reservoir management, were installed with downhole smart systems to control flow from each lateral. Most of these wells were drilled with cemented 7" conventional liner or worked over with 5-1/2" expandable liner for zonal isolation as well as conduit for smart completion in the reservoir.

This paper will present an alternative to convert existing old wells to smart MRC wells equipped with hydraulically controlled downhole valves and swell packers or feed-through open hole packers as zonal isolation in open hole environment. So far four such wells have been successfully worked over and completed with open hole smart completion. Production data shows that not only these wells have achieved significant production gains, but also confirmed that the downhole isolation packers and flow control valves functioned as planned. This paper will also highlight the cost saving advantage of open hole smart completion as well as operational optimization process that led to successful field implementation.
EOS-Based Downhole Fluid Characterization
Authors: Zuo Julian Y. , Zhang Dan , Dubost Francois , Dong Chengli , Mullins Oliver C. , O'Keefe Michael , Betancourt Soraya S.
Published: October 2008

Downhole fluid analysis (DFA), together with wireline formation testing tools, provides real-time measurements of reservoir fluid properties such as compositions of four or five components/groups and gas/oil ratio (GOR). With the introduction of a new generation of DFA tools that analyze fluids in situ, the accuracy and reliability of the DFA measurements are significantly enhanced. Furthermore, the downhole measurements of live fluid density and viscosity are integrated into the new tools. Direct pressure and temperature measurements of the flowline ensure capture of accurate fluid conditions. To further enhance these advanced features, a new method of downhole fluid characterization based on the equation of state (EOS) approach is proposed in this work.

The purpose of this work is to develop a new approach to maximize the value of DFA data and perform quality assurance and/or quality control (QA/QC) of DFA data. The basic inputs from DFA measurements are weight percentages of CO2, C1, C2, C3-C5, and C6+; live fluid density; and viscosity. A new method is developed in this work to delump and characterize the measurements of C3-C5 (C2-C5) and C6+ into full-length compositional data. The full-length compositional data predicted by the new method are compared with the laboratory-measured gas chromatograph (GC) data up to C30+ for more than 1,000 fluids, including heavy oil, conventional oil, volatile oil, rich gas condensate, lean gas condensate, and wet gas. A good agreement is reached.

Furthermore, based on the delumped and characterized compositions, an EOS model is established that can be applied to predict fluid phase behavior and physical properties on the basis of DFA data as input. The EOS predictions are validated and compared with the laboratory-measured PVT (pressure/volume/temperature) properties for more than 1,000 fluids. The GOR, formation volume factor (FVF), and density predictions are in good agreement with the laboratory measurements. The established EOS model is then able to predict other PVT properties, and the results are compared with the laboratory measurements in a good accord.
CO2 and Flue Gas Coreflood Experiments for Enhanced Coalbed Methane
Authors: Mazumder Saikat , Wolf Karl Heinz
Published: October 2008

Laboratory core flooding experiments with CO2, N2 and flue gas were carried out on coal in an experimental high P, T device under in-situ conditions. These experiments will be able to give an insight into the design of the injection system, management, control of the operations and the efficiency of an ECBM project. Although the experience gained by the oil industry represents a valuable starting point, several problems are still to be studied and solved before CO2 improved deep coalbed methane production may be operationally feasible. These are all related to the heterogeneous nature of the pore structure of coal, and in particular the presence of fractures. More specifically, a number of questions need to be addressed, e.g. what are the conditions under which the fluid in the micro-pores of the coal is displaced by the CO2 in the presence of competitive adsorption; what is the role of compositional heterogeneity and fracture anisotropy of coal for the injection design and the efficiency of the sequestration in relation to the swelling and shrinkage characteristics of coal; how does the mobile and the immobile water in the coal affect the exchange process. These questions can be answered by means of downscaled laboratory experiments that are capable of accurately describing the coupled process of multiphase flow, competitive adsorption, and geo-mechanics. In the laboratory conditions have been simulated to match pressure and temperature at depths of 800 to 1000 m. Under those conditions the injected CO2 remains supercritical. Upto now, the results show that dewatering will be an essential step for successful ECBM combined with a CO2 sequestration process.
Differential Swelling and Permeability Change of Coal in Response to CO2 Injection for ECBM
Authors: Mazumder Saikat , Wolf Karl Heinz
Published: October 2008

The matrix volume of coal swells when CO2 / CH4 adsorb on the coal structure. In coalbed gas reservoirs, matrix swelling could cause the fracture aperture width to decrease, causing a considerable reduction in permeability. On a unit concentration basis, CO2 causes greater degree of coal matrix swelling compared to CH4. Much of this difference is attributable to the differing sorption capacity that coal has towards carbon dioxide and methane. This condition in a coal reservoir would lead to differential swelling. Differential swelling will have consequences in terms of porosity / permeability loss, with serious implication for the performance and implementation of carbon sequestration projects.

Coal can be understood as a macromolecular cross-linked polymeric structure. An experimental effort has been made to measure the differential swelling effect of CO2 / CH4 on this macromolecular structure and to theoretically translate that effect in terms of porosity and permeability. A unique feature of this work is that, real time permeability measurements were done to see the true effect of differential strain from CH4 saturated coal core flooding experiments.
Innovative Well Operations from a DPII Vessel: A Case Study
Authors: Glennie Simon , Leeson Tom , Rowson Ian
Published: October 2008

The traditional need to carry out all well operations from a rig can be expensive and delays valuable well construction programmes. Rigless intervention, including the use of subsea wireline lubricators and installing subsea Xmas trees on wire, utilising a Dynamically Positioned (DP) intervention vessel has long been accepted in some areas of the world as a cost-effective and efficient alternative to traditional rig-based methods.

In 2005 it was recognised internally that the ability to intervene without a traditional rig would be of potential future benefit. An aspirational work programme was developed including both well operations such as subsea Xmas tree (SSXT) change out, well abandonment and production enhancement operations was developed. The scope generated was sufficient to justify the mobilisation of a suitable vessel and the necessary specialist equipment such that these operations could be completed. It was also recognised that the vessel would offer further options for construction support, commissioning start up support and field maintenance activities. The actual 1st job undertaken of SSXT installation on Vincent project was not recognised as a possibility until late 2006.

To date 7 SSXT installation operations have been completed successfully in approx. 370m of water on the Vincent field in Australia, this was followed by wireline intervention to commission wells for operation to/from the host facility. A number of plugged and abandoned wellheads were also severed and recovered from the seabed. The vessel was also utilised extensively for other subsea operations. Operations are ongoing to complete the expansion of the Vincent project and a number of production enhancement opportunities are being planned for the near future including PLT surveys, water shut offs, and Gas-lift valve installation.

This paper will detail the operations undertaken and the issues to be managed to ensure safe and cost-effective execution. Furthermore the paper examines the unique challenges of translating experience gained to date to the Asia-Pacific region, to deeper water depths, and will discuss the lessons learnt from the planning and operations phases of the project. These will include details of the modifications required to the vessel to convert her from her previous role as a large Supply Vessel (PSV), including the critical elements of the conversion required in order to ensure appropriate Class registration and the successful award of an Australian Safety Case covering all safety critical operations.

Lastly the paper will examine the potential benefits Rigless intervention can offer and the additional cost benefits of incorporating other non-well related activities into the vessel programme.
Performance of Polymer Flood in Sanand Field, India-A Case Study
Authors: Tiwari Deepti , Marathe R. V. , Patel N. K. , Ramachandran K. P. , Maurya C. R. , Tewari P. K.
Published: October 2008

Twenty two years of history of polymer flood in KS-III sand in Sanand field, Gujarat State, India, proves the efficacy of the process in a reservoir of 85°C temperature. KS-III sand of Middle Eocene age, is one of the few successful cases of polymer flooding in such high reservoir temperature. Reservoir is acting under partial edge water drive. Oil viscosity of 20 centi poise led to adverse mobility ratio which resulted in cusping of water in structurally higher wells. Hence polymer flood was considered the best option in this reservoir for improving mobility ratio of oil and overall areal and volumetric sweep efficiency which was also supported by the laboratory studies on native cores of the field. Polyacrylamide polymer was selected for injection.

Polymer flood process in Sanand field has undergone many stages of implementation. After initiation of polymer pilot in an inverted five spot pattern in 1985 with one injector, 4 producers and one monitoring well, it was extended to four inverted five spot patterns in 1993 with nine producers and four injectors. Effect of the injection was visible in terms of reduction in water cut, improvement in oil production and increase in reservoir pressure. Success of pilot projects encouraged to full scale field implementation in 1996–97. Polymer injection was done in peripheral pattern in the main part of the field. Subsequent reviews have been carried out from time to time and mid course corrections have been taken accordingly.

Current paper discusses different stages of development in polymer flood, the steps taken from time to time, lessons learnt and conclusions drawn on the basis of practical experience and reservoir simulation.
Measuring the Effectiveness of Hazard and Risk Awareness Interventions Utilising a Virtual Reality Risk Perception Measurement Simulation
Authors: McGrath Tim
Published: October 2008

In this study oil and gas workers' Risk Perception was measured by their ability to detect, assess and react appropriately to realistic occupational hazards presented in a computer virtual reality simulation. This technique provides immediate results to determine whether attendees have benefited from training. Whilst all participants benefited from the training, some benefited more than others due to the appropriateness of the training for their current level of Risk Perception. This paper presents two successful training techniques which lead to an improvement in Risk Perception of the participants. It is anticipated that further testing with larger sample sizes will identify the components that are best suited to each level of participant.
Successful Case History of a Novel Open-Hole Horizontal Well Completion in Saudi Arabia
Authors: Al-Naimi K. M. , Lee B. O. , Shourbagi S. M. , Kelkar S. K. , Shaheen M. , Johnston B.
Published: October 2008

Horizontal completion technology has progressed dramatically over the last six years, with the latest technical barriers being eclipsed with open-hole technology. These completions have allowed multiple zones to be fractured and the benefits of utilizing open-hole horizontal completion technology have been well documented. The efficiencies and benefits of utilizing open-hole completion with mechanical isolation, has lead to the operational benefits of multiple fracturing operations being pumped in one continuous operation equating to time savings, more efficient fractures, faster cleanup and less safety hazards. Conventional methods of cementing a liner in place, perforating, fracturing and repeating the process for the number of stages required can be very time consuming with added expense of removing the frac plugs with coiled tubing after the operations have been completed.

When drilling a horizontal well, there are two preferred completion options. First, the horizontal section can be completed open-hole or with slotted/preperforated liner. In these completions effective stimulation along the horizontal wellbore is almost impossible. The second completion system, cased/perforated liner, requires cementing the production liner and running multiple isolation systems to effectively treat different sections of the wellbore. Multiple coiled tubing trips and multiple rig-up and rig-down of the stimulation equipment is required. These multi-stage horizontal completions take weeks to complete at high costs and elevated risks. Ultimately, the high completion costs or the lack of production due to ineffective stimulation make many reservoirs uneconomical to exploit.

This paper will discuss the new completion designed specifically for open-hole fracturing of both sandstone and carbonate reservoirs. This innovative, field proven system greatly increases the effectiveness of fracturing operations by segmenting the lateral and producing mechanical isolation points in the wellbore using the high performance open-hole packers. The system allows precision placement of fracturing fluids to maximize post-fracture productivity of the well. The completion system is run as part of an uncemented liner and spaced out based on the required number of stages. Once in place the packers are hydraulically set and fracturing treatments are pumped in separate stages but as a single continuous operation. By eliminating cementing requirements, natural fractures are undamaged and easily stimulated during pumping operations.
Facts and Data on Environmental Risks—Oil and Gas Drilling Operations
Authors: Rana S.
Published: October 2008

Purpose of the paper is to review environmental aspects of Oil & Gas drilling in view of economics of the projects benefiting industry professionals. Oil & Gas exploration, including offshore & directional drilling pose long and short-term environmental risks. These risks are primarily associated with (a) contamination due to drilling wastes (muds, produced waters, byproducts, etc.); emissions from drilling sites and potential runoffs, (b) natural gas/oil leaks and spills, and (c) direct effects on human health. The drilling fluids circulated through the well hole contain toxic materials (including oil/grease, arsenic, chromium, cadmium, lead, mercury, & naturally occurring radioactive materials). The composition of drilling muds and produced waters varies widely depending on location & depth of well; and type of drilling fluid. Produced waters potentially impacting the surface or groundwater are typically disposed of in a deep aquifer, but there is still the threat of accidental release from temporary storage. Contributing to air pollution are also the potential emissions of hydrogen sulfide present in natural gas deposits. Its short & long-term direct effect on human health could be severe, from unconsciousness to death within a few breaths. Statistically, 0.5-1% of exploratory wells result in blowout, causing harmful emissions. Additionally, pressurized contents of a geologic formation literally explode out of the new well, severely impacting environment and the project economics.

The paper includes summary statistics of environmental incidences, their causes & preventions based on actual projects. The accidents are related to well drilling, pipelines incidents and spills/leaks listed by cause (equipment failure, corrosion, joints, materials, etc.).

Paper presents guidelines and economically feasible options to minimize risks to environment & human health. It also provides an overview of the environmental concerns, project economics and sustainability issues.
Decline Curve Analysis of Oil Production in Low Permeability Reservoirs with Great Heterogeneity
Authors: Huo Da , Li Li , Fan Xiaodong , Yu Yanmin , Li Kewen
Published: October 2008

There have been many models of decline curve analysis in estimating reserves and production in petroleum reservoirs. It is difficult to evaluate the models because the true value of reserve in oil reservoirs is usually unknown. Previously, comparison and analysis among limited models has been made using spontaneous imbibition data. In this study, an approach to using core flooding experimental data was proposed to verify and evaluate the decline curve analysis models. Four representative models (exponential, hyperbolic, harmonic, and the mechanistic Li-Horne models) were chosen to predict and match the oil production in low permeability core samples and oil reservoirs. A systematic comparison among the four models was conducted by using the sum of squared residuals, regression coefficient, and the true values of reserve (for core samples) as the evaluation parameters. Both experimental and reservoir data from a low permeability oil reservoir with great heterogeneity were used. It was found that it was difficult to appraise the goodness of the decline curve analysis models by using the sum of squared residuals and regression coefficient as judging parameters in some cases. The small values of the sum of squared residuals or the great values of the regression coefficient could not guarantee small error in the predicted reserves. It may be a suitable approach to using experimental data of oil production in core samples with different permeability to evaluate decline curve analysis models. The results demonstrated that the Li-Horne model and the exponential model predicted the reserves satisfactorily for experimental data of water flooding in the core samples with low permeabilities.
Energy from Abandoned Oil and Gas Reservoirs
Authors: Zhang Lingyu , Yuan Jianguo , Liang Hongbin , Li Kewen
Published: October 2008

Petroleum and Geothermal industries are embracing the present boom in production of crude oil and power generation. At the same time, longevity or sustainability of this boom is worried about. In petroleum industry, a lot of oil and gas wells have been or will be abandoned. There have been few ideas and methodologies regarding how to utilize the abundant resource left in the oil and gas reservoirs. In this study, we pointed out that these oil and gas reservoirs might be transferred into exceptional enhanced geothermal reservoirs with very high temperatures by oxidizing the residual oil with the injected air. A concept to generate power from these exceptional enhanced geothermal reservoirs by using geothermal power generation technology was proposed. Using Du84 reservoir (heavy oil) in Shuguang oil field, and Ren9 reservoir (light oil) in Renqiu oil field, both from PetroChina as examples, we estimated the possible energy and the income that might be generated from such exceptional enhanced geothermal systems. We speculated that both the oil and geothermal industries will boom much longer based on this study.
The Potential of CO2-EOR in China Offshore Oilfield
Authors: Xiang W. , Zhou W. , Zhang J. , Yang G. , Jiang W. , Sun L. , Li J.
Published: October 2008

In South China Sea, the geological reserve of CO2 is huge. With the unanimous agreement of a series of problems caused by CO2 emissions, as an effective method to consume CO2, CO2 injection for enhanced oil recovery (EOR) has been investigated and reported by many researchers.

An extensive review of previous reported CO2-EOR projects is provided in this paper. According to exploring and analyzing the factors influencing CO2-EOR, and combined with the specialty of offshore conditions, reservoir evaluation of China offshore CO2-EOR is suggested in this paper. Based on the evaluation suggestion, the Chinese offshore oilfields were screened and the South China offshore oilfield close to CO2 reserve was conformable. This paper also describes the feasibility of CO2-EOR in the South China offshore oilfield from fundamental studies. The relationship of reservoir oil and CO2 showed that reservoir oil had good dissolving capacity to CO2. CO2 could effectively dissolve in and displace residual oil. The experimental results show that under reservoir conditions, CO2 could be in the one-contact miscible at 20 MPa, a slight higher than the formation pressure of 17.27 MPa. CO2 and oil could be in near miscible under formation conditions. The lab research work funded a further investigation on application of CO2-EOR in China offshore oilfield.
Recovery Optimization Strategy for Thin Oil Column Reservoir with Large Gas Cap: Case Study of Gunung Kembang Field
Authors: Febrianto Dwi Hudya , Aimar Amritzar , Afandi Tomi , Setiawan Dadan , Handayani Ricky SW
Published: October 2008

Effective exploitation of the thin oil rim in the Gunung Kembang field is particularly challenging because of the huge size of the overlaying gas cap, and the thickness of the oil rim varying between 25 to 40 feet gross pay interval, not to mention the sizeable water aquifer underlying the reservoir. Horizontal wells were implemented since 1992 to enhance oil recovery by reducing gas and water coning, nevertheless, oil recovery still remain around 3%. As the pressure is depleting, horizontal wells revealed to pose higher risk than before, just like in the second stage of horizontal drilling in 2004, where water breakthrough and total loss occurred. The plan to add more horizontal wells to add recovery was coincided with POD commitment to deliver gas by gas cap blow down.

This paper presents a team effort to formulate optimization strategy for maximizing oil recovery and revenue while delivering gas as committed in POD. Integrated reservoir characterization that comprises of carbonate depositional study, and reservoir simulation was conducted to best manage not only the drilling location but also number of wells and production strategy for next horizontal wells.

Carbonate depositional study using existing logs and core data revealed the best oil potential zone in Baturaja formation in terms of porosity and permeability. Meanwhile, reservoir simulation grid was aligned with the zonation from carbonate deposition model, after that the performance of existing 10 wells was history-matched to develop an improved strategy. Sensitivity analysis conducted demonstrated that locating horizontal oil wells in the upper oil rim near the gas oil contact proved to be the best strategy for depletion of the oil rim.

Among five scenarios developed, one final scenario was selected to accommodate both oil recovery optimization and gas cap blow down. This scenario includes eight additional horizontal oil wells while utilizing their produced gas to accommodate gas commitment, without drilling another gas well. Oil recovery is expected to rise to about 8% while gas is being delivered according to POD.
X-O-T Technology for the Treatment of Crude Oil Emulsions
Authors: Nahmad David G. , Kmiec Isabela , Nasir Awalludin , Udau Isrom
Published: October 2008

SCOMI Energy in cooperation with PETRONAS Carigali Miri Crude Oil Terminal (MCOT) implemented a pilot project to demonstrate the effectiveness, technical and economical, of the emulsion treatment technology known as X-O-T for emulsion resolution and crude oil recovery.

A typical emulsion was drawn in batches from Emulsion Storage Tank into Scomi's system. This emulsion was processed on a continuous flow basis through a custom designed system in order to break "resolve" the emulsion and separate its constituents for further disposal or storage of the oil as "dry oil".

X-O-T is a proprietary process utilized to break emulsions of hydrocarbons/water/solids. The process is based on a series of chemical reactions that interact with other reagents releasing heat and neutralizing the non-covalent forces that form the bonds between the substrate and the wetting agents making it feasible to separate the components of an emulsified mixture of minerals, water and hydrocarbons.

A mechanical process for separating the emulsion constituents is needed.

The results of the processing of this emulsion were very promising. All solids contained in the initial emulsion were removed from the mixture; some of small particles in the colloidal size range were transferred directly to the recovered water.

The emulsion was resolved up to 92% to 98% leaving a small tough invert emulsion that contained no solids and a high concentration of heavy hydrocarbons. Recovered solids were "dry" and had hydrocarbon content around 15%. Recovered water was treated using ionic polymer. The result rendered clean water.

This technology can prove to be very economical not only for oil recovery, but also as preventative maintenance. The removal of all solids from this stream can strongly impact the tank farm operations budget by reducing downtime, increasing storage capacity and removing expenses such as tank cleaning and sludge processing.
Dynamic Modelling of CO2 Injection in a Closed Saline Aquifer in the Browse Basin, Western Australia
Authors: Yang Qingjun
Published: October 2008

This paper presents results of dynamic modelling of CO2 injection in a closed saline aquifer in the Browse Basin, Western Australia. The storage capacity of CO2 in this type of aquifer is ordinarily greatly limited due to the rapid pressure buildup during injection. This study shows how closed systems, including faulted or lithologically confined reservoirs, may be made suitable for larger volumes of CO2 storage. Based on the analysis of radial flow models, the inability of the reservoir to accommodate displaced water was considered to be the main reason for the rapid pressure increase. Simulation results show that producing brine from the reservoir can greatly relieve the injection pressure and increase the storage capacity. Under an optimum injection-drainage strategy, the risk of CO2 breakthrough at the drainage well can be decreased and the cost of draining brine can also be reduced. The studied site is estimated to be able to contain at least 20 years of CO2 injection, at an injection rate of 1 million tonnes per year, before breakthrough of CO2 at the drainage well. With this type of drainage strategy, more "closed system" geological sites could be made available for storing CO2.
Lithological and Petrophysical Core-Log Interpretation in CO2SINK, the European CO2 Onshore Research Storage and Verification Project
Authors: Norden B. , Förster A. , Vu-Hoang D. , Marcelis F. , Springer N. , Nir I. Le
Published: October 2008

The storage of carbon dioxide (CO2) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from power plants to the atmosphere and to mitigate global climate change. The CO2SINK project is a R&D project, mainly supported by the European commission, the German Federal Ministry of Education and Research, and the German Federal Ministry of Economics and Technology, targeted at developing an in situ laboratory for CO2 storage. Its aims are to advance the understanding of the processes involved in underground CO2 storage, evaluate applicable monitoring techniques, and provide operational experience, which all contribute to the development of harmonized regulatory frameworks and standards for CO2 geological storage.

The preparatory phase of the project involved a baseline geological site exploration and the drilling in 2007 of one injection and two observation wells, as well as the acquisition of a geophysical baseline and geochemical monitoring, in Ketzin located near to Berlin, Germany. The target saline aquifer is the Triassic Stuttgart Formation situated at about 630–710 m (2070–2330 ft), that is made of siltstones and sandstones interbedded by mudstones. A comprehensive borehole logging program was performed consisting of routine well logging to which an enhanced logging program was added for one well that record nuclear magnetic resonance and borehole resistivity images predominantly to better characterize the storage formation. A core analysis program carried out on reservoir rock and caprock included measurements of helium porosity, nitrogen permeability and brine permeability. Carbon dioxide injection started in 2008 and will last for about 2 years.

The paper focuses on the integrated approach of combining lithological and petrophysical data from both laboratory and well logging analysis predominantly for the reservoir/storage section of the Ketzin site. This method was successfully applied in two wells with extensive core data. In the third well, where few core data exist, the section was characterized successfully by analogy.
Regional Pore Pressure Modeling Strategy at Tiger Shoal, GOM, USA
Authors: Stafford T. W. , Goode R. W.
Published: October 2008

Accurate prespud pore pressure prediction is key to well planning and drilling execution on the deep (> 18K ft) HPHT gas wells of the Gulf of Mexico (GOM) shelf. These predrill pore pressure predictions are a key part of the general subsurface hazard assessment. A pore pressure prediction strategy that combines petrophysical, geophysical, 1.5-D hydrodynamic basin modeling and centroid effects was developed for use in the Tiger Shoal deep gas exploration and development drilling program at Flatrock.
Unique Solution for Fracture Isolation Resolves Water/Gas Breakthrough Challenges in a Horizontal SlimHole Well
Authors: Al-Mumen Adib A. , Al-Umran Mohammed I. , Agrawal Pradeep , Jorgensen Thomas , Smith Peter E.
Published: October 2008

Preventing water or gas breakthrough and equalizing flow is one of the primary challenges of producing from horizontal slimhole wells. This paper will present a "first-of-its-kind" concept in which swellable packers were used to isolate a water-producing fracture to prevent/delay water/gas breakthrough and equalize flow across a 3–7/8-in. horizontal open hole. The water-producing fracture was encountered during drilling of the slimhole horizontal in a naturally fractured carbonate reservoir. Prior to the introduction of swellable technology to the oilfield, satisfactory solutions for isolation in open hole slimhole wells had not been available. Although swellable technology was new to the area, after careful analysis of the situation, the operator and the service company decided to use four swellable packers to compartmentalize the hole.

The completion configuration was successfully run, and the well was brought into production at good rates and with a low water cut.
The Development of a National Gas Separation and Sub-sea Multiphase Flow Loop Facility
Authors: Amin Robert , Pack David
Published: October 2008

The past decade has seen oil and gas exploration and development move into a new phase as hydrocarbon reserves are increasingly found in remote locations, with a large number in the deepwater environment. This change has produced the need to develop sub-sea based technologies that are flexible, durable and simple in the face of high capital and operating costs.

Sub-sea developments produce greater flow assurance and intervention challenges.

Solutions are needed to address the low seawater temperature conditions that lead to problems within trunklines, such as hydrate formation / plugging, wax precipitation and sand accumulation. The long distances that are involved in remote location developments limit the effectiveness of existing technologies to minimise the problems.
Sand/Well Vacuuming Technology with Concentric Coiled Tubing: Best Practices and Lessons Learned from Over 600 Operations
Authors: Li J. , Crabtree A. , Kutchel M. , Diaz J. , Reyes W. , Dugarte R. , Peña L.
Published: October 2008

Sand production is a common problem with unconsolidated formations. It is very challenging to successfully remove formation sands with conventional methods in a large deviated wellbore with a low pressure gradient formation1.

Since 1995, a technology combining concentric coiled tubing (CCT) with a jet pump has been developed and used to remove both the drilling fluids and solids. Initially it was developed for horizontal heavy oil reservoirs where pressures are low and viscosity is high, without placing hydrostatic loads on the reservoir. The job data from more than 600 sand/well vacuuming operations worldwide has been compiled into a database.

This paper reviews the well information and the key operating parameters: maximum depth, bottom hole pressure gradient and pump rate. The engineering challenges, best practices and lessons learned for the sand/well vacuuming process are also summarized. Analysis of this data yields a better understanding about this vacuuming technology and provides good guideline for future practice.

Case histories are provided which demonstrate how to deploy the different sand/well vacuuming bottom hole assemblies (BHA), to; increase the penetration capacity with a jetting tool; entering multi-laterals with an entry guidance system; accessing small size holes with a micro-vacuuming tool; and to achieve extended reach under extreme conditions.

Post job analysis indicates CCT vacuuming technology reduces the skin damage and increases the production compared to non-vacuumed wells. Moreover, the details from sand and other fluid influx profiles obtained along the wellbore based on the analysis of the returns during the vacuuming process, could be used to evaluate well production and assist in formulating a management strategy.
Study and Application of the Technology of Subdivision Controlled Limited Entry Fracturing in Reservoir with Many Thin Layers
Authors: He Liu , Zhongguo Wang , Qingping Wang , Hongtian Yao , Jifeng He , Zhixin Wang , Shifeng Zhang , Jiachen Zhang , Zhiyao Li
Published: October 2008

Since the year of 2005 the output of new well has been basically from the tertiary infillers in Xingnan development block in No.5 Oil Production Plant, Daqing Oilfield Co., Ltd., where we mainly produce from the thin and poor quality oil layers of tabulated reservoirs (those reservoirs included in the reserve tabulation which was made at the beginning of Daqing Oilfield) and the untabulated reservoirs (those reservoirs excluded from that reserve tabulation). The intended zones often grow in reservoir groups of Sa II SaIII and Pu I. In such reservoirs, the sublayers to be perforated in are comparatively more, the thickness of sublayers is quite little and the perforated interval is very long, which is averagely more than 180m. Because the reservoir lithology, physical and oil-bearing properties are all comparatively worse than normal, the conventional limited entry fracturing technique can not meet the demand of stimulating such interlaminated reservoirs any more. So we advanced this technology at the following aspects:

We determined the recognition method to difficult-fracturing sublayers and the corresponding treatments by studying on the lithology and electrical characteristics of calcareous argillaceous layers in the interlaminated reservoirs. On the basis of the study on the regularity of interference between fractures from theory and the proof application of this regularity, we concluded the threshold value of the fracture spacing which would lead to inter-fracture interference. We also defined the delivery rate and sand amount to a single fracture/a single hole through both the theoretical estimation and on-site statistical analysis of the operational discharge and the amount of sand used.

Through the above researches, we not only created our own perforation designing method, but also established the criteria of selecting layer as well as the technical idea for this technology.

We successfully applied this improved limited entry fracturing technology to over 500 wells in reservoirs with many thin layers. As the results of this work, we not only reduced the operational cost of the limited entry fracturing technology but also gained ideal economic and stimulating effects. This improved limited entry fracturing technology is also applicable to the fracturing treatment in gas field.
Development of the Stybarrow Field, Western Australia
Authors: Hill Robin , O'Halloran Gerry , Napalowski Ralf , Wanigaratne Bimal , Elliott Alison , Jackson Mark
Published: October 2008

The Stybarrow Field is a moderate size biodegraded oil accumulation reservoired in early Cretaceous slope turbidite sandstones of the Macedon Formation in the Exmouth Sub-Basin offshore Western Australia. Excellent quality 3D seismic has enabled attribute mapping and probabilistic seismic inversion to be used to both estimate the net sand distribution of the reservoir and facilitate optimal well placement. The reservoir comprises excellent quality, but poorly consolidated, sand rich turbidites up to 20m thick. The field lies in >800m of water and has been developed with four near horizontal gravel packed production wells connected to an FPSO via sub sea trees and flowlines.

Water injection is required for pressure maintenance and produced gas is re-injected into the nearby Eskdale oil & gas field, the oil leg of which is produced via a single horizontal well. Pressure support is required from field start-up due to lack of aquifer support. Horizontal production wells with high productivity indices are required for optimal drainage. Downhole sand control is provided by a combination of open-hole gravel packs and sand screens.

Key subsurface challenges were faced in the development of the relatively thin reservoir containing biodegraded 22° API oil with little or no aquifer support. Lateral reservoir variations have important implications for connectivity and therefore the optimal drainage of such fields.

The Stybarrow project involves a nine well subsea development and a double hulled FPSO, the Stybarrow Venture, with capacity of approximately 80,000 barrels of oil a day. Oil came on stream in November 2007 and nameplate production was reached within weeks of first oil. The Stybarrow and Eskdale fields which make up the project have estimated recoverable oil reserves of 60 to 90 million barrels and estimated field life is 10 years.

This paper documents a multidisciplinary approach applied during the appraisal, development and early production life of the field. Static and dynamic data on a variety of scales (i.e. seismic, well data, bed boundary resistivity modeling, inter-well interference testing and early production performance) have been integrated into detailed 3D geological models, which have enabled a greater understanding of reservoir connectivity, as well as a better estimation of ultimate oil recovery.