bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using an Expert System to Diagnose Formation Damage Mechanisms and Design Stimulation Treatments for Gas Storage Wells
Authors: Xiong Hongjie , Robinson Bradley M. , Foh Steve 
Published: December 2007

Abstract
In gas storage wells, many different types of formation damage can occur that dramatically curtail injection and withdrawal rates. Some of these damage mechanisms are similar to producing wells (mud/cement damage during drilling, completion problems, etc.); however, some types of damage are more specific to gas injection and storage (bacterial growth, contaminants, etc.). All these different damage mechanisms require different stimulation treatment methods and fluids to increase injectivity and deliverability. However, diagnosing the correct type of formation damage is not a simple task. The process requires gathering specific types of data and interpreting the results. Correct diagnosis of the actual damage mechanism(s) and design of the appropriate treatment requires expertise and experience.
Over the years, numerous studies have been performed on formation damage, and a vast amount of experience has been obtained on the design of stimulation methods and fluids to remove damage. However, this knowledge and experience is not always available or accessible to engineers dealing with stimulation design, especially with the unique types of problems associated with gas storage reservoirs.
This paper describes a comprehensive computer model designed for gas storage wells to help engineers diagnose formation damage and select the best stimulation treatment. The model combines domain knowledge bases with the best available expertise using fuzzy logic and expert system technologies. After diagnosing the most likely formation damage mechanism(s), based upon input data, the program will select the best treatment method and recommend treatment fluids and additives for the stimulation.
Innovative Sand-Control Screen Assembly Enables Successful Multi-Lobe Frac Packs in Adverse Recompletion Conditions
Authors: Cox Morris , Roane Tom , Sanders Mike , Clarkson Brad , Fitzpatrick Harvey 
Published: December 2007

Abstract
Industry experience has shown that frac pack completions can provide effective production stimulation and reliable sand control for unconsolidated sand reservoirs. One of the more rewarding areas of opportunity is in the completion of longer and more complex intervals that can be stimulated with a single frac pack treatment. Here, the cost saving of a single completion versus the cost of two or the recovery of reserves from pay zone sand added to the completion interval can add significantly to the cash value of the well.
This paper discusses an innovative screen that has a concentric shroud that can treat two separate and distinct sand lobes during a single frac-pack operation. Two cases histories illustrate the use of an innovative assembly that uses the new screen to enhance the stimulation and sand control results of frac pack completions on unconsolidated sand reservoirs with complex lithology and permeability contrast. The capabilities of this technology have brought a long-sought-after solution to fruition.
Development of the Alba Field – Evolution of Completion Practices, Part 1: Open Hole Screen-Only Completions to Gravel Pack
Authors: Murray G. , Brookley J. , Ali Syed , Davidson E. , McMillan N. , Roberts J. 
Published: December 2007

Abstract
The Alba reservoir (located in the Central N Sea) is a highly permeable, unconsolidated sand body with lenses of reactive shales within the reservoir sand. From the initial decision to exploit the field using horizontal wells there has been an evolutionary approach to selection of the most appropriate drilling fluid and completion technique. The development of the field has been marked by a drive to increase productivity and reduce the total cost of the ownership of the asset.
The major challenges in completing wells on this field involve issues of sand control and inhibition of reactive reservoir shales.
Initially, completions were prepacked screens in open hole and the fluid used to drill the reservoir section was oil based mud. Productivity was lower than expected but improvements were achieved by switching to sized salt water based mud and initiating a very stringent QC procedure for the drilling and completion fluids. However, screen failure occurred very soon after the wells became water cut and the wells almost invariably sanded up. More recent changes have involved a switch to sized calcium carbonate water based mud and open-hole gravel packs.
Because the geology of the Alba field dictates that there is almost always some shale exposed in the open hole reservoir section it was found that the gravel carrier fluid needs to be equally as inhibitive as the drill-in fluid
Since 1998 thirteen open-hole gravel packs have been successfully completed, in all cases with high flowrates and no history of sand production.
This paper deals with the performance of the various techiques applied and details the best practices derived for optimum productivity and screen longevity.
Stressman Website to Screen for Potential Geomechanical Problems Due to Depletion
Authors: Palmer I. , Ispas I. , Higgs N. , Moschovidis Z. , Patillo P. , Smith B. , Beecroft W. 
Published: December 2007

Abstract
A new core testing strategy has been implemented, to gather the correct data to estimate potential geomechanical problems. Right after core testing has been done, the core results are combined with in situ stress estimates, and other reservoir/well information. These data are submitted to a new screening software called Stressman, to evaluate the chance of certain geomechanical problems (such as subsidence, or casing failure) occurring during the life of a field. Predictions are quantitative and risk-weighted, and provide a preliminary step for geomechanical assurance. If Stressman indicates a problem is likely, then a full-blooded modeling effort can be undertaken to better assess the situation. Stressman provides an effective methodology for gaining a quick, "first pass" quantitative assessment of what is likely to happen geomechanically, when otherwise all that can be done is to make an educated guess.
Screening modules available in Stressman include: (1) extra production from compaction drive, (2) surface or seafloor subsidence, (3) general reservoir yielding (leading to potential skin buildup), (4) perm loss during drawdown/depletion, (5) casing buckling due to compaction,
(6) casing crushing, (7) sand production, (8) fault slip due to depletion. Also linked within the Stressman website is information about the data required for the screening modules: how the data are defined, when/how to collect the data, etc.
Discussed are some recent Stressman applications, which include the following:
full Stressman suites run in deepwater Gulf of Mexico plays, which provide a valuable database for future comparison. evaluation of subsidence due to reservoir compaction estimate of maximum allowable drawdown in a cased/perforated well risk of casing buckling or crushing
Advances in Well Completion Design: A New 3D Finite-Element Wellbore Inflow Model for Optimizing Performance of Perforated Completions
Authors: Ansah Joseph , Proett Mark A. , Soliman Mohamed Y. 
Published: December 2007

Abstract
Overall productivity of perforated wells is influenced by a complex interaction of diverse factors, which include the length of the individual perforations, casing entrance hole diameter, perforation shot density, phase angle between the perforations, and the degree of damage inside and around the perforations. This paper presents a new wellbore inflow model that provides a more accurate means of quantifying the effects of these individual parameters on productivity and skin factor associated with perforated completions.
With the introduction of API RP43 Section IV testing, in-situ perforating geometry is more accurately determined. To take advantage of this more complete perforation description, a new wellbore inflow model is developed. This model incorporates the cone-shaped perforation geometry with a tapered tip that has been observed in the laboratory for years. For the first time, the asymmetric, spiral distribution of perforations around a wellbore is modeled using a full 3- dimensional finite element model with over 30,000 elements in each perforation layer instead of the 2-dimensional and quasi 3-dimensional models used in the past.
Productivity results from the new 3D model are compared with previous models to demonstrate the improvements to the inflow predictions. The effect of reservoir anisotropy on perforation design is also studied over a wide range of shot densities and phasing. Results that highlight the effect of reservoir anisotropy are presented in this work.
The new results from a parametric study are used to build a database, which is used for optimizing perforation completion design.
Field Experience Frac Packing Near Gas/Water Contacts
Authors: Guichard Joel A. , Stewart Brian 
Published: December 2007

Abstract
The ability to frac-pack near gas/water contacts without incurring premature water break through has been a source of concern and debate within the petroleum industry. In this paper, well histories of five-gas wells frac-packed near gas/water contacts are reviewed, establishing a proven method of sand control under those conditions. Log sections and post-frac analyses coupled with production histories establish a basis for future completions utilizing frac-pack technology. Reduced fracture lengths with an emphasis on tip screen outs has proven to be the key to obtaining successful water-free frac-packs in completions with recognized gas/water contacts.
Production Enhancement Through Horizontal Gravel Pack
Authors: Walvekar Sunil , Ross Colby 
Published: December 2007

Abstract
A customer in Middle East had been conventionally completing horizontal oil wells with all welded, wire-wrapped screens because of problems of heavy sand production and fines migration. The wire-wrapped screens would plug up within a very short time, requiring intervention services to wash the screens or to perform stimulation treatments to bring the production back to normal. The frequent plugging not only resulted in reduced oil production but also in increased operational costs because of the intervention required.
Based on the success of other operators who had been experiencing similar problems, the customer decided to try an openhole gravel-pack technique to reduce the plugging of screens in their horizontal wells. In order to assess the concept, the customer requested that a service company that had been performing this type of treatment with great success gravel pack three wells as a trial program.
The service company agreed. To properly perform the gravel pack operations, the service company provided the downhole completion equipment, chemicals, surface pumping equipment and brought experienced gravel-pack personnel to perform the horizontal gravel-pack operations in the candidate wells.
The completions were performed without any major operational problems. After completing the wells, the customer initiated hydrocarbon production. The horizontal gravel-pack treatments provided a production increase in all 3 wells. One of the wells, which was not producing any oil before the treatment, started flowing oil, and two to four times earlier production was noted in the other wells over a period of time. The wells have continued to produce at these rates since these jobs were performed approximately 10 months ago.
The horizontal gravel-pack completions have helped the customer meet the oil production rates needed for economic feasibility and have further enhanced field economics by eliminating the need for intervention services and their related cost.
A Cost-Effective Approach To Improve Performance of Horizontal Wells Drilled in High Permeability Formations
Authors: Arangath R. , Ogoke V. C. , Onwusiri H. N. 
Published: December 2007

Abstract
We describe the application of a high hydraulic horsepower jetting system to deliver treating fluids in horizontal wells drilled in high permeability formations to improve their performance.
This high hydraulic horsepower jetting system was originally developed to remove scale from tubulars. The same system with some minor modifications can be used to deliver treating fluids with high energy at downhole conditions therefore reducing the overall amount of treatment fluid for some specific applications.
On newly drilled wells this means less rig time to perform the post completion cleanup. Two case histories are presented where a newly drilled horizontal well was treated successfully with less than half of the volume typically required for such application.
The same jetting system can be used to perform regular cleaning operations of horizontal wells with inexpensive fluids reducing also the overall treating fluid volumes thus generating an additional saving on pumping time and logistics. Application of this jetting system in horizontal producers has evidenced that produced gas and water rates can be reduced with such cleanup treatments. Five horizontal well cleaning case histories are presented.
The system can also be used in conjunction with a simple fluid tailored to treat a well specific problem such as unplugging sand control screens from drilling and formation fines. Again with the use of the high hydraulic horsepower jetting system the use of chemical products that require special handling or have a high cost can be minimized. A case history is described and includes pretreatment and post treatment production logs.
Finally two applications of this high hydraulic horsepower jetting system to remove bacterial growth from deviated gravel packed injection wells are also presented.
Facts from Fiction : 4D Seismic Model-Based Interpretation
Authors: Burns C. Scott , Aggio Alcides , Gjøystdal Håvar , Santos Rogério 
Published: December 2007

Abstract
4D seismic technology is becoming routinely incorporated in reservoir management by some of the majors—to improve reservoir characterization for EOR, identify unswept oil, GOC, hydraulic communication, infill well locations. To estimate changes in seismic properties due to production, generating the reservoir's theoretical seismic response is indispensable—for guiding interpretation and quantification in terms of saturation and pressure change.
Simulating the reservoir's seismic response to potential rock and fluid distributions is essential for relating 4D seismic information to production—especially for inverting seismic information to an estimate of acoustic impedance change and Poisson's Ratio change. The choice between 1D-, 2D-, 3D-raytrace or full elastic seismic simulation depends on the structural complexity of the reservoir and overburden, the reservoir's elastic profile, and the potential artifacts from differences in the seismic acquisition & processing parameters.
Given the potential pitfalls and limitations of both modeling and data, it is necessary to visually relate geologic, engineering and geophysical information (shared-earth-modeling) to guide the quantification of seismic information for reservoir model updating and history matching. Relating different data types measured at different scales requires a case dependent development of rock physics transforms and downscaling methodologies for updating the high-resolution geologic model with results from the flow-simulator.
To illustrate the above in the context of potential impact on reservoir management, three examples are shown: Deepwater Brazil water-injected oil field with evolving critical gas: 4D seismic analysis of two 3D surveys; utilizing 1D and 3D raytrace modeling.North Sea gas-injected oil producing field: 4D seismic analysis of three 3D seismic surveys acquired during 8 producing years; utilizing 1D seismic modeling.North Sea reservoir: synthetic AVO time-lapse seismic study comparing 2D raytrace and 2D HybriSeis (raytracing above reservoir, full elastic modeling of reservoir).
Processing Schemes of Wet Sour Gas and Sweet Dry Gas in Oil Production Facilities of Mexico
Authors: Verdejo Fierro Jorge , Martínez Miguel Peregrino , Rodriguez Cruz José A. 
Published: December 2007

Abstract
Actually in oil production facilities of Mexico one of de main problems is the wet sour gas transport through long distances (about 125 miles) to gas processing plants of similar way sweet dry gas used for platform fuel and gas lift is transported too trough long distances. This paper proposes processing schemes of wet sour gas and sweet dry gas close to oil production facilities to avoid the problems in the gas transport such as generating multiphase flow, gas condensation in pipelines, high pressure drops, more frequent pigging, high corrosion rates and obtain revenue generation and added value with recovery LPG and pentane plus. Using these methods we will obtain much better results than before. These strategies provide a better way of saving energy, better oil production facilities and environmental protection. All of these benefits are in addition to the obvious increased economics benefits from trading more products. Although these schemes seem will be new in oil production facilities of Mexico they are being used by other international oil companies under similar conditions. The schemes proposed in this paper are applicable to actual and future oil production facilities of Mexico where it is handling and transporting gas. This paper introduces in oil production facilities of Mexico schemes for handling, treatment and gas transportation. These Strategies will contribute to resolving the actual problems from handling transport multiphase flow.
Marlin Failure Analysis and Redesign; Part 2, Redesign
Authors: Ellis R. C. , Fritchie D. G. , Gibson D. H. , Gosch S. W. , Pattillo P. D. 
Published: December 2007

Abstract
Following the review of the initial investigation of the tubing/casing failure on the Marlin A-2 well1, this second paper in the series addresses application of the failure analysis to the remaining Marlin wells. The fact that all five of the initial Marlin penetrations were predrilled up to the completion stage has the following consequences:
The remaining wells can be expected to be exposed to the same loads as the failed A-2 well; The remaining wells have the same vulnerability as the failed well, as only two material differences in well design exist between the A-2 well and subsequent A-3 through A-6 wells: (1) The 10-3/4 in. tieback casing in Well A-2 was grade P-110 -on subsequent wells, it was grade N-80; and (2) Well A2 intermediate casing (tapered 13-3/8 in. × 10-3/4 in.) cement top was designed to not come into the preceding 16 in. liner, whereas on subsequent wells, the intermediate casing (tapered 13-5/8 in. × 10-3/4 in.) cement top was designed to come inside preceding 16 in. liner, with collapsible foam strapped to the outside of a portion of the 10-3/4 in. section; Apart from the redrill option, one does not have complete freedom in devising solutions for the remaining completions.
Within the limitations posed by predrilling, well design concepts were developed and screened using agreed risk acceptance criteria for health/safety/environment, do-ability, and operability. Based on the risk profile and cost associated with each option, a Vacuum Insulated Tubing (VIT)/Fiber Optic completion concept was selected.
After the VIT well concept was selected, an extensive assurance plan was initiated which involved the physical testing and analysis of every component in the new well design. This paper focuses on this redesign process, and includes insights on: The analysis of annular fluid expansion, focusing on the sensitivity of the calculation to fluid and formation properties;The importance of thermal modeling of various types of completion fluids;The performance of tieback casing connections in less conventional combined load regions such as compression and external pressure;Full scale qualification testing of VIT to obtain overall heat transfer coefficients for both the tube body and the coupling.
The final paper in this series2 discusses the implementation and assurance of the solutions resulting from this discussion.
Design of a Drilling Rig for 10,000 ft Water Depth using a Pressured Riser
Authors: Leach C. , Dupal K. , Hakulin C. , Fossli B. , Dech J. 
Published: December 2007

Abstract
This paper presents the requirements for a drilling rig to drill in up to 10,000 ft of water using a pressured riser.
An analysis of deepwater wells drilled was carried out to determine what characteristics (Water depth, drilled depth, number of casing strings etc..) these wells had. A "look forward" portfolio of wells was constructed as the target for the design of the rig. A full QRA was conducted to examine the impact of emerging technologies such as Expandables and Dual Gradient and to determine which choices for rig components were appropriate.
The paper includes an outline rig design for deepwater for West Africa and one for GOM operations. An outline specification for the well systems (BOP, riser configuration) is also included.
A comparison is made of the impact of drilling deepwater wells with this "new" approach versus using the "conventional subsea BOP" arrangement. The paper also includes details of how the "new" approach may be applied to existing rig types and how it may be applied to a new-build.
The cost implications of this step change are examined. Fully risked well cost comparisons (‘new" vs "conventional") are provided along with some comment on the risks and consequences of the available choices.
The paper concludes that the "new" rig specifications detailed will allow for deepwater drilling in up to 10,000 ft water depth and that in some cases there will be significant overall well cost savings.
Drilling Salt – Effect of Drilling Fluid on Penetration Rate and Hole Size
Authors: Whitfill Donald , Rachal Greg , Lawson Jim , Armagost Ken 
Published: December 2007

Abstract
Drilling a deep, high-pressure sub-salt well is both expensive and a mechanical challenge. There are a number of issues that create difficulty. Drilling fluid selection in the past has focused on drilling a gauge hole, with little concern on the issue of penetration rates.(rate-of-penetration.) Drilling a gauge hole is still an important issue for an exploration well and a critical issue for a development well is to prevent well-bore collapse. High operating day-cost for deep-water drilling is placing additional emphasis on drilling rate, as reflected by the rate of penetration (ROP) and rotating hours. This concern raises the issues of how to most effectively improve penetration rate and/or how to drill the well bore with a single pass. Should a water base mud (WBM) or a synthetic oil base mud (SBM) be used. Should you drill a pilot hole and then under-ream, under-ream while drilling, or drill without under-reaming by using a bi-center bit? If water base muds are selected, can you use a controlled wash-out approach to either replace under-reaming, or make it faster? This paper will address the issue of SBM versus WBM and the efficacy of using a controlled wash-out approach with WBM. Case histories for the Gulf of Mexico will be discussed.