bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gulf of Mexico Cement Packer Completions Using Liquid Cement Premix
Authors: Eberhardt J. Todd , Shine Joseph 
Published: December 2007

Abstract
A popular and economical method of re-completing wells in offshore Gulf of Mexico (GOM) involves pumping a "cement packer" across a productive zone which the operator wishes to produce. Recently, the application of Liquid Cement Premix (LCP) technology for cement packer completions has shown many advantages. This paper will summarize the operational and logistical process of pumping a cement packer with conventional cement. In addition, the chemistry and properties of LCP along with the process of performing a cement packer completion using LCP will be detailed. The operational and logistical benefits of using LCP will be discussed, concentrating on its ease of transportation and pumping, minimal equipment requirements, consistent slurry properties, and reduced environmental exposure. Best practices recommendations will also be made for cement packer placements, supported by the evaluation of published literature and previous cement packer completions using LCP.
A Case Study of Uncertainty Management for Developing Fluvial Sedimentary Reservoirs
Authors: Zhou Dengen , Wei Michael , Seguin Ron , Wang Zhiyong , Nan Tian 
Published: December 2007

Abstract
We have developed and implemented an uncertainty management plan (UMP) for developing an offshore heavy oil field. The field is located in shallow waters and the oil API gravity varies from 17° to 21°. The reservoirs are fluvial meandering river systems, where sands are relatively thin and poorly connected. Because of limited appraisal data and the complex nature of the reservoir, uncertainty management was identified to be critical to the success of the field development.
A three-part uncertainty management plan have been developed and implemented, which includes a three-stage drilling program, an optimized completion matrix and a production surveillance program. The three-stage drilling program was designed to obtain critical reservoir/geological information with as low risk as possible by optimizing the drilling sequence. The drilling sequence was defined by classifying the development wells into (1) high confidence (HC) wells, (2) high value of information (HVOI) wells, (3) wells that need relatively certain reservoir information to be successful (horizontal wells) and (4) wells that could be optimized with new information. A mix of HC and HVOI wells were drilled first to validate the appraisal data and obtain critical new reservoir data, which were then used to optimize well placement. The drilling results show that the three-stage drilling program has been successful in capturing the upside reservoir potentials and in avoiding drilling low efficient wells.
The fluvial sedimentary environments of the reservoir create great challenges for reservoir management of heavy oil waterfloods. Based on the best practices and lessons learned in developing similar fields, a well completion strategy matrix was developed to mitigate the risks of multi-water/oil contacts and to avoid excess water production.
A down-hole pressure monitoring system was also installed as part of the surveillance program. The strategies used for selecting the wells to be installed with pressure monitoring gauges were developed based on the well types and the reservoir connectivity. This paper provides a great example of uncertainty management in developing complex reservoirs.
Wireless Measurement Systems for Efficiency Improvements and Desired Management Data
Authors: Lueders Wallace M. 
Published: December 2007

Abstract
This paper describes the important benefits and design considerations of system architecture that will provide a robust, reliable license-free wireless network for industrial sensors in heavy industrial plant environments. The characteristics of commercially available devices and communication protocols are discussed including the benefits of spread spectrum radios compliant with FCC Part 15 rules. Although FHSS provides some measure of protection if a frequency or set of frequencies is noisy, careful network system design and implementation is essential if periodic sensor measurement or control is to be reliably achieved over the lifetime of the installation.
Typically, the electromagnetic environment of industrial sites is not well understood, therefore it is important to survey the area prior to system installation to characterize the conditions and design wireless networks accordingly.
Finally after system installation, continuous self-checking and system monitoring should be carried out to alert of any degradation in performance and to allow for dynamic modification of the radio network as external conditions require.
Sustained Gas Production From Acid Fracture Treatments in the Khuff Carbonates, Saudi Arabia: Will Proppant Fracturing Make Rates Better? Field Example and Analysis
Authors: Zillur Rahim , Petrick Mark 
Published: December 2007

Abstract
Acid fracture treatments in the carbonates are widely applied to enhance well productivity. Some laboratory experiments conducted on actual core specimens under in-situ conditions illustrate that the etched conductivity can reduce with time and eventually close the fracture. In some 100+ wells that have been fractured thus far in the Saudi Arabian Khuff gas reservoirs, long-term sustainability of fracture lengths and conductivity has been demonstrated through fracture and production diagnostics. The phenomena of fracture closure observed in the laboratory studies on certain cores may not therefore be generalized to represent all reservoirs and fields. Nevertheless, longer fracture lengths than generally achievable by acid fracturing are often desirable, particularly in gas condensate fields. Proppant fracturing can create longer fractures and has potential for application in such fields.
This paper provides field cases and evaluates fracture effectiveness from treatment pressure, pressure transient tests, and production data. Initial computation of fracture properties using measured data during treatment and production transients combined with analysis of pressure transient tests performed later during the production life indicate continued presence of induced fracture. Assessment of fracture operations, reservoir flow characteristics, and mechanical properties suggests that the high rate, high volume acid treatments, and formation heterogeneity in terms of layering and permeability variation which helps in uneven acid etching and thus enabling wormholes to stay open contribute to the long-term sustainability of fracture conductivity, half-length, and well performance. The paper evaluates these parameters and provides an assessment on acid fracturing.
Condensate accumulation is occurring in the Khuff reservoirs and this is affecting production rates. Several typical wells are examined to illustrate this point. Liquid dropout is unpreventable, but its effects can be reduced or postponed with longer fractures. Thus the need for proppant fracturing is evident.
Saudi Aramco has started testing the viability of proppant fracturing in the Khuff carbonates. The results obtained so far indicate that careful candidate selection and treatment design are needed to guarantee fracturing success. The selection criteria, treatment design and results of Saudi Aramco&#39;s first ever proppant fracturing in a Khuff reservoir are examined in this paper.
Improved Method of Cementing Solid Expandable Tubulars
Authors: Fanguy Charles Joey , Mueller Dan T. , Doherty Dale R. 
Published: December 2007

Abstract
The successful isolation of solid expandable tubulars (SET) with cement presents a considerable engineering challenge. The primary task in slurry design is to maintain "true fluidity" at static downhole conditions. The slurry must remain both fluid and stable after placement until the expansion process is completed. Failure of the slurry to remain fluid and stable after placement can prevent the successful expansion of the SET. This property, of being both stable and fluid, is difficult to achieve with conventional cement technology because conventional slurries tend to settle under downhole conditions after an extended period of quiescence. This instability leads to density segregation and potential formation breakdown in the lower sections of the well.
A second obstacle that must be overcome to successfully cement a SET is inter-particle attraction (gellation) that can occur once the cement slurry is placed. Minimizing inter-particle attraction/gellation reduces the likelihood of forming voids or channels (micro-annuli) in the finished cement sheath, which can jeopardize effective zonal isolation, the essential performance requirement of any well cementing operation.
The test method currently used to evaluate the properties of conventional cement slurries during the anticipated expansion time is the API RP-10B modified hesitation squeeze simulation. Unfortunately, this test method does not simulate accurately the conditions under which the cement will be placed. For example, the test procedure does not allow adequate time for gellation tendencies to occur. Gel strengths are broken every time the consistometer motor is turned on, producing gel strength values that have no more than ten minutes to develop. This test method also does not provide a means to account for any potential delays that may occur during the expansion of the SET.
To enhance accuracy and reliability in SET cementing operations, a test method which incorporates testing storable premixed cement slurries for fluidity time at static conditions as opposed to using the API modified hesitation squeeze procedure has been successfully employed in field applications. This paper will describe the premixed slurry properties and QA/QC procedures that are required for successful expansion of the SET. This paper will also provide test methods and procedures used for fluidity time testing as well as case histories of successful SET cementation.
Getting the Best From the Black-oil Approach for Complex Reservoir Fluids
Authors: Montel François , Quettier Lisette 
Published: December 2007

Abstract
First, this paper presents a novel method used to derive accurate black-oil properties from a detailed EOS model. This entails the selection of the fluid sample, the choice of the simulated experiment and the representation of the composition gradient. In the case of significant compositional grading with a critical or close to critical transition within the reservoir fluid column, the table should be a compromise between (a) the in situ properties versus depth, which allows an accurate fluid in place representation and (b) the property change versus pressure during depletion. We then describe three field cases using this approach: ■A miscible gas injection into an oil reservoir. 1D fine grid simulations show that the black-oil model gives the same property profiles as the compositional ones. At the field scale, we take advantage of the lower CPU time in black oil to better represent some heterogeneity as fairways which could be detrimental to gas injection.■A reservoir with a critical transition developed either by gas or water injection. With black-oil simulations both initial fluid in places and flow behaviour is correctly represented. But, even if the results are more stable than in compositional ones, the CPU speed-up is lower than expected.■A black-oil representation for history matching a reservoir with a critical transition allows us to have a finer description of the geological heterogeneities with a run time lower than the work day.
Finally, we propose improvements of our methodology based on the lessons learned from the simulations of the previous cases.
Dual Permeability Approach to Modeling Fluvial Reservoirs in the Costa Bolivar Region of Venezuela
Authors: Gomez Hector , Herring Todd 
Published: December 2007

Abstract
This paper builds on the results of previous work related to determining the drive mechanisms of the Mene Grande field. Various studies have been performed recently which all have indicated that the dominant water production mechanisms is depletion of the reservoir mustones or shales. This revelation has allowed both old and new data to be viewed in a new context which has led to a greater understanding of the reservoir bahviour.
Both the long term, data and recent transient analysis strongly indicate the presence of dynamic system behaving as two separate systems. These two systems can roughly be classified as oil filled sandstone, and water filled mudstone. The permeability and volumetric differences are sufficient to induce a typical layered reservoir response. The field data and supporting studies for this drive mechanism have been reported previously.
In this paper we describe the reservoir simulation methodology adopted in order to best represent this heterogeneus system. A dual permeability model has been used with the mudstone acting as the "matrix" and the sandstone as the "fracture". The matrix-fracture transfer function acts as a very efficient history match parameter both for pressure and water cut.
The results of both conceptual and well by well history matches are presented confirming that the methodology is well suited for modeling such systems. The quality of the water cut match even during the early stages of the work is quite remarkable.
This paper will be focused mainly toward the dynamic model, since the geological model was explained in a previous work (See reference 1 for further details).
Reservoir Study of the Largest Oil Field in Argentina - A Two Reservoir 2200 Well Simulation Model
Authors: Fonseca Claudio Marcelo , Firincioglu Tuba , Fernandez Gustavo , Ozgen Chet , Albertoni Alejandro 
Published: December 2007

Abstract
This paper describes the processes incorporated during the simulation study of the Chihuido de la Sierra Negra Field in Argentina, which is presently the largest oil field in the country. The field was discovered in 1968, and an aggressive water injection program was started in 1995. So far the oil production from this field is 65 million cubic meters and the water injection is 158 million cubic meters.
The field has two separate stacked reservoirs that are structurally complex with different fault systems and fluids. Both reservoirs are highly compartmentalized with each compartment having different water-oil contact. The upper reservoir is composed of 6 isolated geologic layers, with each being different depositional environments (sand bars, dunes, fluvial channels, etc.). The presence of unconformities and volcanic intrusions further complicate the reservoir communication and plays an important role in flow behavior.
Currently, the field has 734 production wells with commingled production from both reservoirs and the isolated zones with in the upper reservoir. Approximately 1250 injection strings are currently injecting water.
The purpose of this study was to provide a detailed reservoir characterization to optimize recovery and to create a simulation model with predictive capability that can be used in improving field management. To achieve this purpose a 900,000 cell simulation model was constructed.
This paper will discuss some of the challenges encountered during the history matching of the field model. The identification of the compartment boundaries and their associated water oil contacts (57 contacts) required the development of a new consistent approach. This method provided significant accuracy and time savings over the traditional approach of iterating between history matching and reservoir characterization. The overwhelming volume of data and the volume of simulation results for 2200 well strings required special considerations for pre- and post-processing. New tools were needed to quickly modify the simulation arrays and review all the wells in an efficient and timely manner. As the history matching progressed many additional practical tools were developed. This paper will discuss the significance of these innovations and tools to achieve a successful history match in a timely manner.
Lightweight Cement Formulations for Deep Water Cementing: Fact and Fiction
Authors: Rae Phil , Di Lullo Gino 
Published: December 2007

Abstract
In the past few years, oil companies have ventured more frequently into deepwater areas in the search for hydrocarbons. This trend is likely to continue, or even accelerate, in the next few years and, if anything, we are likely to see ever-greater water depths.
There are several aspects of deepwater wells that make them particularly challenging, from an engineering perspective, through all phases of the process – construction, production, intervention and abandonment. This paper, however, focuses on the issues surrounding deepwater well cementing, primarily during the well construction phase.
This has been an area of intense interest in recent years, due to industry realisation that the deepwater environment had one or two surprises for drillers. Most notable amongst these is the problem of shallow water flows that can easily wash out the weak, unconsolidated sediments, resulting in seabed subsidence and loss of the hole. Other issues include the presence of shallow gas and gas hydrates, strong subsea currents and extremely low fracture gradients, with the ever-present risk of lost circulation or wellbore collapse. The low seabed temperature, which can be below freezing, also depresses the normal geothermal gradient to a variable depth, depending on the thermal properties of the strata.
None of this is good news for cement, which is required to have short thickening time, rapid development of mechanical properties, a fast liquid:solid transition and low permeability to provide casing support, cope with the risk of influx and provide a long term hydraulic seal, amongst other things. This has driven the development and marketing of a host of proprietary cementing systems that claim to address some, or all, of these problems.
This paper reviews the deepwater cementing issues, in detail, and examines the physical and mechanical properties of various cement systems to assess which parameters are truly critical to success. It combines laboratory data with field case histories and working practices in several parts of the world, to help engineers decide on the best formulations for cementing deepwater wells.
Solving Well Construction Challenges Without Downsizing the Well, Using Solid Expandable Liners
Authors: York Patrick , Ring Lev , Terry Jim , Slater Keith , Innes Gareth , Stephenson David 
Published: December 2007

Abstract
In the pursuit of profitable well construction, operators are challenged to drill cost-effective wells while being prepared for the unexpected. Flows, lost zones, sloughing shales, and over-pressured zones are typical examples of unplanned well events that occur while drilling through troublesome formations.
Using conventional remedial methods, such as drilling fluid additives or lost-circulation pills, can prolong non-productive periods and dramatically increase drilling costs. Setting a drilling liner earlier than planned creates the risk of introducing an expensive sidetrack or losing the well altogether.
Solid expandable casing solutions, applied historically as a last-resort effort to save the hole section or even the well, typically carry with them a reduction of hole size, while the use of cement in conjunction with expandable slotted products has been used successfully without loss of hole size; however, for the most severe challenges, solid expandable products are needed.
This paper describes an alternative solid expandable liner system that can address a wide variety of well construction challenges without the need for downsizing a well section.
Openhole expandable "full-bore" liners that use proven cement-less formation-to-casing sealing elements can be used to address troublesome formations during drilling operations, allowing continued drilling of the well with the same size bit post remediation. Additional expandable openhole full-bore liners can be installed below the first if other trouble formations are encountered.
Typically, these solid expandable full-bore liners need only remediate short wellbore sections and therefore can become very cost efficient compared to long solid expandable liners. The tiedback expandable openhole liner (OHL), which must be tied back to the previous casing string, dictates that the next hole section be reduced in size. Applying these full-bore systems immediately on encountering well challenges can significantly reduce the flat time on the drilling curve.
The monobore well is under development, but the expandable full-bore system could be commercially available in the near term. This new openhole wellbore remediation tool can offer immediate and significant financial benefits to well construction. As a contingency solution, the system can be used to downsize wells, reducing well construction costs at the well or field level.
Impacts of Petrophysical Cut-Offs in Reservoir Models
Authors: Lalanne Bruno JP. , Massonnat Gérard J. 
Published: December 2007

Abstract
Petrophysical cut-offs are commonly applied so as to discard non-producing pay, yet, several aspects must be balanced one against the other in the process.
On one hand, considering present hardware and grid size limitations, one of the main benefit of cut-offs is that the relationships between petrophysical parameters are better preserved at the upscaled model grid scale. Otherwise, some bias between porosity, permeability and water saturation distributions may result from the upscaling process, due to the non-linear dependences between those parameters.
Conversely, applying cut-offs may tend to downgrade volumetrics and reservoir connectivity, and alter the actual reservoirs dynamics.
The overall process must therefore aim at defining an optimized set of cut-offs providing the simplest yet accurate upscaled model. This set must be basically adapted to both rock-type and recovery mechanism.
Some case studies are shown to illustrate how cut-offs can limit upscaling bias.
The benefits of both "total" and "effective" porosity – saturation approaches are briefly reviewed. We illustrate how "rock-types" characteristics differ in effective and total domains, and how cut-offs must therefore be tuned in each case.
Impacts of cut-offs on static volumetrics must be quantified. This can be conveniently achieved by visualizing the whole cumulative curve of "net hydrocarbon volume" vs. cut-offs values for each rock-type.
We present a handy way of testing and visualizing multiple combinations of nested cut-offs, which allows to distinguish critical from redundant or secondary cut-offs.