bluuebunny/crossref_metadata_2025 huggingface dataset:
Data Analysis of Barnett Shale Completions
Authors: Grieser B. , Shelley B. , Johnson B. J. , Fielder E. O. , Heinze J. R. , Werline J. R. (Rusty)
Published: December 2007

The north Texas Barnett shale illustrates successful commercialization of an unconventional reservoir. However, it took 17 years to evolve from pumping crosslinked gel (XLG) carrying more than 1 million pounds of proppant per job to slick water fracs (SWF) consisting of large volumes of water and small quantities of sand. This transition to SWF stimulation opened the door for widespread development that has advanced the Newark East (Barnett shale) to the largest producing gas field in the state of Texas.

This paper investigates Barnett completion strategy during the time period from 1993–2002. The 393-well dataset includes completion, reservoir, and production data. Unique data visualization tools were used to investigate various completion parameters and their effect on production.1

This unbiased look at a large block of data challenges some of the preconceived opinions about Barnett shale, including:

The Barnett shale is a continuous/homogeneous formation yielding commercial production in all instances. XLG fracture stimulation is damaging to the Barnett, and SWF always outperform XLG fracs. High rates and large volumes of fluid and proppant always give higher production. Reservoir quality is unimportant or has a negligible effect on production outcome. The effect of changes in stimulation variables on production is readily apparent.

We found that production results show a broad scattering when crossplotted with various completion and reservoir inputs. This result is not uncommon when analyzing field data. The large number of variables and scatter within the data required the use of data clustering techniques to extract useful information. Advanced data mining techniques were used, including self-organizing maps (SOM) to reduce the statistical noise and highlight completion and reservoir parameters directly affecting production. The results show a production outcome based on reservoir quality and completion strategy.
Collaborative Decision Making in Operations-Centre Environments
Authors: Taylor D. , Fosse K.
Published: December 2007

The oilfield of the future vision, as pursued by almost all of the oil and gas majors, has wide-reaching implications for the way that the industry operates that go beyond mere technology implementation. To date the industry has focussed on the acquisition and transport of data to decision makers so as to capitalise on the opportunities to optimise productivity, efficiency and recovery of the field. However, attention is turning to those decision makers and the tools, methods and work processes that will support their activities. Of particular relevance to this debate is the role of collaboration and the ways in which integrated multi-functional teams can work together to make better and faster decisions.

In an effort to gain better insight into the potential benefits from working in such new collaboration environments, Chevron, Hydro and Shell decided to sponsor a Joint Industry Project with Epsis and SAIC. This project has been set up to analyse and test central topics related to operation centres for Production Optimisation, using the facilities of the Epsis Operating Centre Environment.

This paper defines what is meant by collaboration in the context of Production Optimisation and discusses the various forms of collaboration, physical and virtual, that are possible. It also sets out a framework in which to evaluate the extent to which collaboration can be used in work processes and decision scenarios. This framework is the starting point for the analysis and re-design of work processes and the paper presents an approach to how work processes might be tested within an operation centre.

It is recognised that operation centres will be significant developments within the organisation and will affect both people's work habits as well as have an effect on organisation design. The paper presents some of the challenges associated with implementing these facilities and associated working practices and some of the solutions that organisations may adopt to help manage these changes.
When are we Going to Address Organizational Robustness and Collaboration as Something else than a Residual Factor?
Authors: Hepsø V.
Published: December 2007

We see an increasing acknowledgement of the importance of work processes and change management in e-field initiatives. However, it is argued in this paper that the E&P business in general tends to lack a framework and the concepts to approach the social nature of work and collaboration. Several studies show the challenges of realizing global concepts, standardized work processes and seamless integration of data. The paper discusses how the social nature of work must be addressed. It also shows what a more open-ended understanding of the work practices of subsurface professionals’ can mean for "intelligent energy". Seven propositions based on an understanding of integrated collaborative environments as information ecologies are set up and presented using examples from ongoing e-field/integrated operation projects. The work practices presented are from the subsurface and production optimization domain. Examples are from Statoil, using my company as an example of an industry that has particular work practices also found elsewhere in the business. This kind of work is knowledge intensive, highly dependent upon information and communication technology for the retrieval and presentation of data and information. A shared understanding among professional subsurface and petroleum engineering professionals of this information is enabled with the help of primary and articulation work. These two types of work enable communication, collaboration and decision making. Finally, in the conclusion some suggestions for development work within integrated collaborative environments based on the propositions will be presented.
An Offline Approach Utilising New Slickline Technology
Authors: The Giang Ha , Dinh Ngoc Tran , Flores D. , Wendlinger F.
Published: December 2007

The oil and gas industry continuously strives to develop tools and techniques to meet and exceed operational objectives with less cost. These efforts have brought about advancements in downhole tools that enhanced slickline technology, making it a more versatile means of providing accurate depth measurement so that more complicated services can be performed1. Likewise, development of slickline deployed inflatable packers also exemplifies the on-going industry endeavors to conform to a business model that simplifies costs, operations, and logistics2.

This case study involves work done on the Rang Dong Oilfield located 160 kilometers offshore S.R. Vietnam. In operation since 1998, this field has produced oil and gas from sandstone and granite basement reservoirs since 1998. In all four existing wells in this field that were studied, a workover campaign was performed to install gas lift valves because of declining reservoir pressure. To prevent formation damage while pulling the existing completions and running the new completions, with gas lift mandrels, isolation plugs were chosen to isolate the producing intervals. This technique was used because of its ability to minimize rig time by working offline and because the plugs could pass through a small restriction and set in the tubing joint of the tail pipe without requiring a landing nipple profile.

The innovative techniques for well workovers used in this project utilized slickline deployed inflatable technology to provide economic alternatives traditionally reserved for more costly options. Borrowing from computer age terminology, this approach is know as the "offline" approach which conveys the meaning that well preparation work takes place before the rig is placed on location. As implemented, the plug isolated the formation from kill weight fluid before the rig was needed so that production tubing could be removed and reinstalled with gas lift mandrels. The use of this method reduced rig cost by an average of eighty-four hours per well and realized a savings of $2MM for the entire project. Not addressed in this report is the incremental revenue generated by eight additional days of early production achieved by completing the project ahead of schedule.
Transient Simulations Assist Hydrate Remediation Efforts in Deepwater Gulf of Mexico Dry-Tree Wells
Authors: Harun A. F. , Krawietz T. E. , Erdogmus M.
Published: December 2007

Hydrate plugs were formed above the mud line in three dry tree oil wells in the Gulf of Mexico. One plug was formed during slick line operations that caused the tool string to get stuck at ∼3000 ft (above the mud line) while pulling out of the hole, even though the well was believe to have been freeze protected with LDHI. The other two plugs were formed when trying to open the downhole safety valves by pumping crude to return the wells to production after they were shut-in due to hurricane evacuation. Several unsuccessful attempts to melt the hydrate blockage included pumping methanol through a chemical injection line below the plug and lubricating in glycol above the plug. As a last attempt, before utilizing coiled tubing, injecting hot oil into the tubing-casing annulus was considered. Transient simulations were performed to determine the required injection temperature, rate, and time. Well integrity issues were mainly associated with the compatibility of hot oil with elastomers and possible asphaltene or paraffin precipitation in the annulus. The tool string came loose after 12 hours of hot oil injection. The hydrate plugs in the other two dry tree wells melted after 6 and 60 hours of injection time, respectively. The slick line operation was reviewed and recommended practices were put in place to prevent future hydrate blockages. A revised restart procedure has been implemented to eliminate the hydrate problem in future startups.
Permanent Plug and Abandonment Solution for the North Sea
Authors: Liversidge D. , Taoutaou S. , Agarwal S.
Published: December 2007

The numbers of ageing fields in North Sea are only increasing as more and more brown fields are reaching end of productive life. The challenge today in the North Sea is to maximize production from what remains and also to safely, economically and optimally abandon the wells, which can no more produce. The operators have hence started looking for options to abandon wells in a highly government regulated environment.

Permanent Plug and abandonment is done with the objective for the well to be sealed and isolated forever. This long term sealing requirement is one of the principle parameters to measure the success of abandonment. This becomes even more critical in the North Sea as the cost of operating offshore and risked cost of returning to re-abandon a leaky well run into millions of dollars. Furthermore the environmental liability of cleaning up slicks from a leaky well is also a concern. Technically sound abandonment practices are necessary for long-term isolation to protect the environment and to avoid the eventuality of an expensive re-abandonment.

This paper presents

A discussion of abandonment regulations and requirements. A case history for permanent abandonment campaigns in the North Sea region UK sector. A discussion of the methodology, materials and techniques used.
Experience in AA-LDHI Usage for a Deepwater Gulf of Mexico Dry-Tree Oil Well: Pushing the Technology Limit
Authors: Harun A. F. , Fung G. , Erdogmus M.
Published: December 2007

A dry tree oil well in the Gulf of Mexico (GoM) was producing water cut above 50 percent that prohibits the usage of the existing anti-agglomorate low dosage hydrate inhibitor (AA LDHI) during extended shutdowns and cold restarts. However, by using the concept of cumulative water cut, defined as the ratio of cumulative water production over the cumulative liquid production, and implementing the strategy to outrun the water during warm up time, the well has been put back on production without any hydrate problems. Thus, understanding the well performance, using the right analytical tools, and challenging the technology limit through creative thinking have enabled the operator to manage the hydrate risk and operate the well at minimum cost.
The Importance of Well Construction and Well Integrity for Reservoir Management— A Mature Field Experience in Sudan
Authors: Tewari Raj Deo , Raub Mohd Razib Bin Abd , Omar Mohd Ismail , Fenghan Bai , Moris Munir , Jelani Jamil , Ramachandran Supra , Fooks Andrew Leslie , Peden James M. , Montague E.
Published: December 2007

This paper describes the importance of well construction & well integrity and its relationship to reservoir management. Productivity enhancement studies in combination with reservoir simulation modeling on the Greater Heglig fields have revealed that well performances and production related problems were largely related to poorly designed wells and poor cementing practices. As a result, water channeling and cross flow across wellbore dominated true well performance characteristics contributing to very high water cuts in the majority of the producers in Greater Heglig fields. Separating the mechanically induced well behaviour from reservoir behaviour helped history matching the wells greatly, findings of which were subsequently validated during the study through running of ultra sonic imaging tool. The ultra sonic logging campaign proved the existence of channels, micro annuli's and cross flow across the wellbore causing a "water channeling phenomena" of up to 90% water cut across majority of the wells. As part of the productivity enhancement program for the Greater Heglig fields, a total of 23 sidetrack candidates have now been identified to capture the remaining developed reserves of ca. 30.0 MMstb, which will otherwise remain unproducible from the existing wellbore's. In addition to this, fit for purpose sidetrack well designs and construction together with good cementing practices will be required to ensure well integrity to improve reservoir management of the Greater Heglig fields.
Evaluation of Drag Reducing Agent (DRA) for Seawater Injection System: Lab and Field Cases
Authors: Al-Anazi H. A. , Al-Faifi M. G. , Tulbah F. , Gillespie J.
Published: December 2007

Thorough experimental studies were conducted to assess the effectiveness of a drag reducing agent (DRA) to increase the flow capacity of transfer line that supplies treated seawater to power water injectors in carbonate reservoirs and ensure it has no adverse impact on water wells injectivity. These studies included: compatibility tests, corrosion rate measurements, flow through tube tests, and coreflood experiments. Experimental results showed that the examined DRA is compatible with the currently used biocides in seawater. Corrosion tests implied that the DRA decreased the corrosivity of seawater by 50%. Flow through tube tests confirmed that the DRA reduced frictional (drag) pressure drop in the tube and increase the flow capacity. The DRA was found to be sensitive to shear where its effectiveness decreased with high shear due to polymer chains degradation. Permeability reduction was observed at higher DRA concentrations. However, degraded DRA gave less damage compared to a fresh batch. The extent of permeability damage increased in low permeability (tight) cores. The DRA caused an external damage on the face of the core, where it was removed by reversing flow direction. The examined treatments (polymer oxidizers) degraded the DRA and restored core permeability. This paper summarizes three successful field cases of this DRA in seawater injection systems. Injection rates of six wells increased up to 34% after the DRA injection in the Brent Alpha offshore field. Injection of a DRA, up to 80 ppm, increased the total volume of seawater injected by 65% in the Gyda oil field, Norway. The use of a DRA in the seawater system of the Galley offshore field resulted in re-pressurizing the reservoir and maintained oil production. Based on the obtained promised results and successful field cases, field application guidelines for using DRA seawater system were summarized.
History and Actuality of Separate Layer Oil Production Technologies in Daqing Oilfield
Authors: Xiaohan Pei , Zhipeng Yang , Li Ban , Yaning Liang
Published: December 2007

Separate layer oil production technologies in Daqing Oilfield were developed and improved continually with the course of the oilfield development. The technologies in the medium-low water-cut flowing period were mainly composed of the oil well packers, the Model 625 oil well regulators and the multipurpose eccentric regulating & plugging control system. In the early high water-cut artificial lifting period, 4 types of mechanical water shutoff technologies including integrated, equilibrium, slip and drillable ones were developed and applied. Furthermore, the double fluid chemical water shutoff technology was successfully studied. In the late high water-cut artificial lifting period, the water detection technology by temperature log and the profile testing technology provide accurate guides in determining the high water-cut layers. Adjustable intervals mechanical water shutoff technology and the single fluid chemical water shutoff technology could meet the requirements of subdividing oil production and water shutoff for artificial lifting wells.
Smart Snake Wells in Champion West—Expected and Unexpected Benefits From Smart Completions
Authors: Obendrauf W. , Schrader K. , Al-Farsi N. , White A.
Published: December 2007

Snake wells are laterally weaving ("snaking") extended reach horizontal wells that drain a number of vertically stacked, structurally dipping reservoirs. This creates multiple drainage points in each sand and effectively achieves a similar drainage pattern to a multilateral well at a fraction of the cost and technical complexity. The wells are completed with multiple hydraulically controlled interval control valves (ICV) and external casing packers or swellable packers. In addition, the completion includes permanent downhole gauges (PDHG) and distributed temperature sensing (DTS). Seven of these smart snake wells have been successfully drilled in Champion West as of April 2006 and three more are planned during the remainder of 2006.

The well design not only facilitates initial clean-up, but is used for reservoir management purposes and to manage gas and water breakthrough. Throughout the well life, variable ICVs are used to achieve equal drawdown along the well bore, leading to a significant increase in reserves by delaying gas breakthrough.

In addition, some unexpected benefits materialized from the use of smart completions: In one case, the smart completion enabled the clean-up of the initially uncompleted toe, significantly increasing total recovery from the well. In another case, the smart completion mitigated the risk from a potentially bad cement job, saving a cement repair job or, more likely, a sidetrack. In another well the flexibility of the design enabled the effective shutoff of water bearing zones that were drilled because of slight departures from the planned well trajectory. Through modification of the planned segmentation an expensive re-drill was avoided.

The smart snake wells have thus been a key enabler for the economic development of the Champion West field and we expect they will continue to add further value over the lifetime of the wells.
Case Study of Fracturing Technology to Thin Barrier in Daqing Oilfield
Authors: Jianwen Yan , Huilan Dang , Jun Lu , Lili Wang , Wei Yang , Ying Yu
Published: December 2007

This paper analyzes the difficulties met in reservoir fracturing in the tertiary infill campaign to recover oil from those thin, low porosity and low permeability sands in Daqing Oilfield. Vertically, these sands are characterized by thin barrier, long stridden interval between two adjacent target intervals. Due to the limitations of the barrier thickness must be longer than 2.0m and the stridden span must be shorter than 40.0m, the existing fracturing technique-separate layer fracturing cannot be adopted in these tertiary infill wells. If these thin, low porosity and low permeability sands could not be fractured, these tertiary infill wells would not produce oil economically. Based on the barrier channeling mechanism-studying results, the minimum limit of the barrier thickness is determined theoretically, 4 types of balance fracturing string have been developed, and 20 tertiary infill wells have been fractured successfully. Thus, an effective stimulation measure-balance fracturing has been developed to produce oil from those poor and thin sands in these tertiary infill wells.
The Profile Modification Evaluation by Electrometric Potential Method
Authors: Feng Guo , Li Zeng , Xuedong Zhang , Wei Chang , Honglin Yan , Jinxiu Hong , Na Li
Published: December 2007

After many years' waterflood, most of the blocks in Daqing Oilfield are faced with the situation of high water cut, high liquid production. More serious problems and difficulties appeared in oilfield development.

Therefore, in order to know the situation of producing wells together with the waterflood distribution and efficiency of water injection wells, it is necessary to adopt an advanced testing method to monitor the flooding direction of injected water, thereby evaluate the effectiveness of profile control on injection well group, and provide reliable information for water flooding in the future.

The Electrometric potential method is such a new technology developed to solve the above problems, available for monitoring the flooding direction of injected water. Its principle is based on that of the conduction-type Electrometric exploration techniques. With it the flooding direction of injected water and other reservoir parameters can be deducted according to the surface potential changes produced by the high ionizing energy of the injected fluid in the desired formation. It can be applied for the following purpose: Determine the flooding direction of injected water;Verify the fault and its closed property.Evaluate the effectiveness of well stimulation measures, like deep profile control etc.
New Class of Meter Solves Old Problem Impacting Well Test Accuracy
Authors: Ward E. R.
Published: December 2007

For the first time in a BP-operated asset, the impact of entrained free gas (not solution gas) in the liquid outlet line of a well test separator is quantified for the purpose of correcting gross fluid volumes and density measurement. This paper describes the results of deploying a sonar based, clamp-on gas void fraction (GVF) meter at a test facility in the Prudhoe Bay Unit (PBU) on Alaska's North Slope.

This particular test facility employs a coriolis meter to measure density and gross flow rate of the oil/water mixture. It was confirmed that discrepancies in allocation factors and individual net oil measurements, especially for cold high viscous crude oil, was due in part to unrecognized gas carry-under in the liquid outlet. Measured GVF associated with wells flowing ‘non-viscous’ oil, the less viscous crude (22 to 32 API) ranged from 0 – 2.0 %, whereas the GVF of wells flowing viscous crude (17 to 22 API) was between 0 – 8% at normal vessel liquid levels increasing to >20% at reduced separator levels.

The additional secondary phase measurement enables PBU to now report real time corrected densities and volumes using an in-house method to calculate water cut. In addition to viscous crude, we believe that application of this technology to smaller, somewhat under-sized separators with less stable operations will provide value across the industry.

Well testing importance is increasing on the maturing fields of the North Slope of Alaska as it is not only used for the critical function of field management that ensures optimum production from a field; it also is a regulatory requirement set by the State of Alaska and may be used for Production Volume Accounting on fields with co-mingled production facilities.
Using High Resolution Lithofacies from Spectroscopy Logs and Microresistivity Images to Optimize Formation Pressure, Sampling, and Interference Testing Operations
Authors: Kear George R. , Kumar Anish , Donaghy Eileen , Guillory Christina , Elshahawi Hani , Ardila Mario , Williamson David , Cantwell Wesley , Briscoe Brian
Published: December 2007

Downhole pressure sampling and vertical interference tests are being conducted more and more as standard practice in the Gulf of Mexico and other deep-water provinces. A key input into the planning of these operations is an accurate understanding of the subsurface lithology, including subtle reservoir internal baffles and barriers. Not only is it necessary to understand where, in depth, the zones of interest exist, but also their compositions.

Log-derived high-resolution mineral-based lithofacies can be used to improve the planning of downhole sampling operations and post-operational analysis. These are computed using borehole spectroscopy and high-resolution micro-resistivity image data. The spectroscopy data is used to classify the rocks into dry-weight mineralogy-based lithofacies based on a specifically designed ternary-diagram classification system. Calibrated high-resolution micro-resistivity image data is integrated with the generated dry-weight mineralogy-based lithofacies to compute a final mineral-based high-resolution set of lithofacies. All the computations can be accomplished on a workstation within a short time. The final lithofacies can be presented as a detailed geological column, or be input, as numerical data, for additional computation and modeling.

These lithofacies can be used to make sampling and pressure point selections. The speed of computation makes them useable for this purpose. The output can be quickly delivered to the decision makers whether in the office or at a remote location. The geological display of the lithofacies makes it readily usable and preferred for choosing sampling locations, whether for pressure or fluids. The inherent mineralogical content combined with the higher resolution bedding directly addresses the need to identify potential zones of interest otherwise indistinguishable. Critical depositional events such as maximum flooding surfaces, condensed sections, reservoir seals such as marl layers and shales, continuous or interbedded, are immediately identifiable with these lithofacies.

The use of log-derived high-resolution mineral-based lithofacies helps place the tool probes and/or packers at optimum formation and depth locations, thereby reducing risk and operating time, easing interpretation, and maximizing data and sample recovery.
Strategies and Techniques for a Giant Sandstone Oilfield Development: A Road Map to Maximize Recovery
Authors: Lu XiaoGuang , Wang YuPu , Zhang YongQing
Published: December 2007

Daqing, the largest heterogeneous multi-layer none marine reservoir oilfield in China celebrated its 45th birthday in Ocotober 2005. Boasting 27 continuous years of plateau oil production over one MMBOD, the largest industry polymer-flooding oilfield in the world, and excellent developing effect, its development strategies and techniques applied provide a road map to maximize oil recovery: Life cycle reservoir studies give insight into reservoir, and provide a foundation for plan of development, implementation of infilling, and associated workover jobs such as zonal stimulation, zonal water plugging.Early reservoir pressure maintenance by internal water flooding maintains reservoir pressure close to its original status, providing sufficient reservoir energy, enabling high and stable production rate for a long period as well as improving recovery.Performance monitoring conducted in the whole process of development, of which, separate layer performance monitoring is one of the most important foundation for in-depth understanding subsurface development potential.Pilot tests are conducted before any key development strategies and measures are applied to ensure their success.Separate layer production/water injection of multi-layer and heterogeneous reservoir and novel completion are the key measures for enhancing poorly drained reservoir water flooding, improving its sweeping efficiency.Multi-time and progressive infilling drilling develops bypass oil resulting from the geological complexities of reservoirs.Widely applying polymer flooding enhances oil recovery by over 10%.Innovative technology makes development of marginal reservoirs/fields economical.

Outstanding development of the giant field has proven the validity of above strategies and techniques with an oil recovery factor current at over 51% in the main block.
Laboratory Aspect of Chemical EOR Processes Evaluation for Malaysian Oilfields
Authors: Ibrahim Zahari , Manap Arif Azhan Abdul , Hamid Pauziyah Abdul , Yee Vai Hon , Hong Lim Peng , Wyatt Kon
Published: December 2007

Chemical Enhanced Oil Recovery (EOR) processes are being considered for large field applications with recent high price of crude oil. However, applications are generally directed towards onshore environment, with temperature less than 85°C, using fresh water as the injection water. Malaysian oil fields are located offshore, with high reservoir temperatures of more than 100°C and use sea water as injection water. This paper reports on laboratory results that were part of an R&D project investigating the feasibility of increasing oil recovery through chemical EOR processes for oil fields in Malaysia.

Chemical EOR processes investigated include surfactant, surfactant-polymer, alkaline-surfactant, and alkaline-surfactant-polymer. A unique 2-stage softening prepared seawater for the two processes using alkali. Thermal aging studies at 119°C were used to screen chemicals for stability and degradation. Interfacial tension and phase behavior tests of stable chemicals were used to select formulations. Linear corefloods and thermal degradation tests were used to select polymers. Oil recovery studies used field proportioned injected chemical volumes in radial corefloods.

Dilute surfactant processes without alkali recovered little incremental oil. This was attributed to heavy consumption loss of surfactant. Average incremental oil recovery in coreflood studies by alkali-surfactant flooding was 14.6% OOIP and by alkaline-surfactant-polymer flooding was 28.6% OOIP respectively. This proved that there is potential for chemical EOR application in Malaysia.
The Use of Fractional Flow Theory for Foam Displacement in Presence of Oil
Authors: Mayberry D. J. , Kam S. I.
Published: December 2007

Foam has been extensively used in improved and enhanced oil recovery processes in the petroleum industry over decades. Foam is capable of reducing gas mobility dramatically in porous media, and thus helps displacement fronts stable by controlling the mobility ratio between injected gas and reservoir fluids. In this study, models were constructed to investigate the mechanisms of foam displacement in porous media using three-phase fractional flow theory and ternary diagrams. The strength of foam in the presence of oil was accounted for by using a mobility reduction factor (MRF) for the gas phase that can be routinely measured in laboratory coreflood experiments. The use of MRF is a typical way of describing foam rheology in local steady-state modeling.

Results were analysed in terms of saturation paths in the ternary diagrams, saturation velocities, sweep efficiency and effluent history. Two different initial conditions were selected to demonstrate the importance of initial saturation on the displacement: one with oil phase dominant ((Sw, So) = (0.2, 0.8)) and the other with water phase dominant ((Sw, So) = (0.8, 0.2)). At low MRF (i.e., no foam or weak foam), the efficiency of foam displacement was primarily governed by fast-moving spreading waves that rapidly broke through the porous medium resulting in poor sweep efficiency. An increase in MRF (i.e., stronger foam) altered the nature of the displacement front by making it more piston-like through the development of "shock" fronts and improved sweep efficiency significantly. Once shock fronts dominated the displacement, the importance of initial saturation on the mechanisms of displacement became less pronounced. Calculations also demonstrated that a decrease in oil viscosity made the oil phase more mobile and the formation of shock fronts more prolific, significantly enhancing sweep efficiency.

The results in this study imply that if basic fluid properties, injection and initial saturation conditions and MRF are known, one can reliably predict the mechanisms of foam displacement in porous media even in the presence of oil.
Revitalization of the Austrian Oilfields
Authors: Gugu Siegfried
Published: December 2007

Since the early 1940's OMV has produced oil and gas from the Austrian oilfields situated ~30 km northeast of Vienna. Currently around 850 oil wells produce ~5.5 MMbbl/a.

In order to ensure economic field life in decades to come, a number of projects are currently in realization or in planning phase.

One focus aims at drilling exploration wells adjacent to existing infrastructure in order to add additional reserves. The well locations are established by using extensive 3D seismic surveys, shot in and around of already producing fields. Beside the exploration wells drilling of infield producers ensure that the natural decline of the mature horizons can be minimized. Additionally production optimization (change of artificial lift systems, oil well automation, etc.) plays a crucial part in stabilizing production.

Another important factor of mature areas is the existing infrastructure. In OMV's case most of the infrastructure is already more than 30 to 50 years in place and has reached the end of its design life. Increasing maintenance costs and break downs make a renewal unavoidable. 3 major projects are currently in realization: Matzen NEW, Tank Farm NEW and Water Treatment NEW.

These projects will assure that the goal of a significant reduction of maintenance costs and of manpower will be achieved. This will go hand in hand with an increase in reliability and maintainability.

By 2010 all new projects will be completed and most of the old oil infrastructure will be renewed, streamlined and fully automated. Together with the forecasted production increase the Austrian oilfields will then be "Fit for the Future".
Identifying the Improved Oil Recovery Potential for a Depleted Reservoir in the Betty Field, Offshore Malaysia
Authors: Friedel T. , Sanza G. J. , Ali M. I. , Embong A. , Kasap E. , Yusoff S. , Cuauro A.
Published: December 2007

A reservoir simulation model, calibrated with 25 years of production history, was used to determine a cost effective reservoir management and production strategy, which optimises future recovery from an oil rim reservoir in the Betty Field, offshore Malaysia. The reservoirs consist of good quality sands in a coastal depositional environment with an anticlinal structure terminated at the crest with a growth fault. The history match confirmed that A6.0 reservoir, unlike all others in the field, which co-exist within a stacked sequence, is surprisingly isolated from the surrounding aquifers. Prior to its premature shut-in, oil production reached 5000 bopd. However, a drastic decline in reservoir pressure caused the evolution of a large secondary gas cap and a steeply increasing producing gas-oil ratio. The recovery factor for this reservoir stands at 25%, significantly less than for the best reservoirs in the field.

After more than a decade shut-in, secondary and tertiary recovery methods investigated in this study included dump flooding from adjacent reservoirs, gas re-injection and water injection based on an extensive prior screening exercise. The limited prospective increase in reserves highlighted the need for a technically sound but also financially feasible solution. Since the current facilities were not intended for any pressure maintenance or enhanced oil recovery scheme, a number of technical limits arose due to space and weight constraints on the platform. Furthermore, fluid separation and export constraints had to be taken into account. Consequently the reservoir management plan required a field-wide optimization of the scheduled activities in order to identify bottlenecks in the gas handling capacity. Simultaneously with the model study, shut-in wells' production potentials were re-tested in order to gather additional data and, a water dumpflood pilot was implemented.
Techniques of Reinjecting 100% of Produced Water in Daqing Oil Field
Authors: He Liu , Shushan Tang , Xiaoshu Li , Li Zeng
Published: December 2007

In the history of over 40 years of development, Daqing Oilfield has witnessed three phases of development: basic well pattern, infill well pattern, and tertiary oil recovery. To cope with that, three sets of systems including general produced water re-injection, produced water fine treatment re-injection, and polymer flooding produced water re-injection have been set up catering to the varied requirements in injection water quality of different well patterns. Among them, general water re-injection system feeds the basic well pattern and primary infill well pattern; fine treatment water re-injection system serves secondary and tertiary infill well pattern as well as marginal low-permeability oilfields; and polymer water reinjection system is dedicated mainly to polymer flooding blocks.

Aiming to satisfy the requirements of the oily produced water treatment and oilfield water re-injection development, and based on the specifications of the original produced liquid and output water, Daqing Oilfield water treatment system is divided into four subsystems, they are: general produced water treatment, produced water fine treatment, polymer flooding produced water treatment, and clear fresh water treatment.

Original liquid to the produced water treatment subsystem comes from water flooding and dehydration stations, part of the treated water is re-injected to the basic well pattern and the primary infill well pattern, the remaining portion goes through fine treatment before being re-injected into the secondary and the tertiary infill well patterns. Original produced liquid to the polymer flooding produced water treatment subsystem originates from polymer flooding and dehydration stations, and all of which is re-injected to the basic well pattern and the primary infill well patterns after being treated. As for the marginal low permeability oilfields, due to their low permeability, the original liquid coming from dehydration stations is treated straight in the fine treatment station before being totally re-injected, in locations where the produced water quantity can not satisfy the injection demand, underground water and surface water will be treated to reach quality required by the low permeability reservoir injection process.

The key process of the water re-injection technology is to treat the produced liquid into standards required by reinjection. This thesis is to introduce the produced water treatment technologies used in Daqing.
Expandable Casing In India
Authors: Roy Choudhuri Biplab
Published: December 2007

In drilling long drift side tracking well window was cut in 95/8 casing. After window cutting 81/2"hole drilled with kcl phpa (inhibitive) mud wt 12 ppg upto top of LIII. Reason for 12 ppg mud use due to shale instability above top of LIII. FROM LIII top to land point formation is lime stone and low pore pressure require gel polymer mud (low mud wt 8.6-8.7 ppg) drilling this two section leads to complication and well problem as 12 ppg mud will induce loss in limestone formation.

As from 95/8" casing window was cut and 7" liner was lowered to top of LIII next liner to lower 5" and thereafter 31/2 drain hole. 6" drain holedrilling was not possible. By adopting expandable liner system problem was solved. One extra set of 51/2 expadable liner was lowered. 51/2 " bicentre bit was lowered and 6" drain hole was done. Drilling procedure as belowLowered 7" linerLowered 61/8 " bit/6"×7" bicentre bit and enlarged to landing point using near bit 7" reamer. Lowered 51/2" expandable casing. Lowered 51/2" bi centre bit for making 6" drain hole.6" drain hole was possible to drill using expandable liner and drilling shale and low pressure loss zone isolating above two zone
An Integrated Approach to Reservoir Performance Monitoring and Analysis
Authors: Sugai K. , Nishikiori N.
Published: December 2007

This paper presents how an engineered process of monitoring and data analysis can improve reservoir management. Engineers can gain a clear picture of reservoirs by adapting the described approach. This paper demonstrates how our integrated approach can improve reservoir management from a viewpoint of production data analysis. A wide variety of oilfield data have been utilized for experiment and verification of our approach. Five case studies highlight key elements in the integrated approach. Each of the application and highlights of the results includes:

Improved oil rate estimation by integration of well test data and well modeling using Neural Networks. This method improves reliability of oil rate estimate by reducing vulnerability of Neural Networks. Well performance diagnostics by an innovative two dimensional plot of a specialized parameter. It has proved that simultaneous tracking of oil-and-water production is useful in performance-based well ranking. Water flood monitoring and diagnostic by Hall plot for injection wells and derivative of water-oil-ratio plot for production wells. This technique provides detailed information for subsurface water monitoring and control. Infill well drilling candidate selection by visualizing well drainage area superimposed onto geographical information. This quick-assistance approach has been proved consistent with the highly-detailed reservoir simulation. Acidizing optimization from data mining the best-practices by Neural Networks. This method has been proved applicable as an operational quality management tool.

The outlined approach and case studies have shown how the integrated process improves reservoir management in the life of field. The specific engineering methods described are all handy and they can be applicable for any type of oilfield.
Successes Achieved in Acidizing of Geothermal Wells in Indonesia
Authors: Mahajan M. , Pasikki R. , Gilmore T. , Riedel K. , Steinback S.
Published: December 2007

Geothermal reservoirs differ significantly from their hydrocarbon counterparts and so do their remedial treatments. Typically these reservoirs are naturally fractured volcanic sandstones with varying mineralogy found over a wide temperature range. Often the zones of low permeability limit the efficient recovery of heat from these reservoirs. The low permeability could either be inherent or induced by damages occurred while drilling and/or production phases. The drilling phase often experience significant fluid losses, which cool the well and near wellbore zone from the high bottom hole static temperature to the moderate levels that make drilling, cementing and completion of these wells possible. The loss of cuttings and drilling mud to permeable formations and/ or fractures is a major source of damage. Other potential damages occur when the well is put on production. As such it is common for these wells to experience a decline in production owing to such formation impairments.

Permeability in these zones may be enhanced through methods of well stimulation such as acidizing and high-rate injection. Such practices usually employing mixtures of hydrochloric and hydrofluoric acids in various concentrations, have widely been used worldwide but performance has been somewhat spotty and unpredictable. Also owing to the typical difficult locations of geothermal sites, there have been concerns about the logistical and QHSE aspects while planning conventional treatments.

A successful application of a unique acidizing system & other techniques into geothermal wells in Indonesia is presented in this paper. This acid system involves controlled in-situ generation of HF acids based on organo phosphonic acid chemistry. It provides unique advantages in geothermal application in terms of both the enhanced well performance and rightly addressing all the logistics/QHSE issues discussed above. The last treatment with this system resulted in almost 3 folds increase in productivity of well.
A Hybrid Artificial Intelligence Method for the Optimization of Integrated Gas Production System
Authors: Park Hui-June , Lim Jong-Se , Kang Joo M. , Roh Jeongyong , Min Bae-Hyun
Published: December 2007

The optimization of gas production system has been largely based on a nodal analysis approach of individual wells. This approach limits the overall benefit of a field study because it ignores complicated flow interactions among wells during the optimization process, often resulting suboptimal operations. A major impediment in the formal optimization of large petroleum producing fields is the excessive computation time during optimizing processes. The conventional deterministic algorithm can not take into consideration the uncertainties regarding nonlinear and complex systems.

This paper proposes a new hybrid artificial intelligence approach for field-wide optimization of integrated production system including gas reservoir, well flow, and surface production network. An advanced polynomial neural network (PNN) with layer over-passing structure has been developed to replace a relatively time consuming reservoir simulator through robust and systematic search algorithm. The networks are subject to some form of training based on a representative sample of simulations that can be used as a re-useable knowledge base of information for addressing many different management questions.

For an optimal design of gas production systems, this study uses an integrated simulation model implemented by coupling a PNN with surface production network and optimization scheme based on fuzzy nonlinear programming approach to accommodate uncertainties by combining the fuzzy λ-formulation with a co-evolutionary genetic algorithm.

The proposed approach significantly reduces computational effort for optimization of the development scheme within reasonable accuracy. The hybrid optimization method can find a globally compromise solution and offer a new alternative with significant improvement over the existing conventional techniques. This technique provides optimum production rates of each well of the entire production system to deliver the target rates over the period of the gas contract requirements. This system has been validated by synthetic case study offering an important element for management of gas production strategies and field development.