bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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

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

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

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

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

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.
Multifunctional Chemicals for West African Deep Offshore Fields
Authors: Poggesi Guido , Hurtevent Christian , Buchart David
Published: December 2007

In Deep Offshore Fields, the injection of chemicals demands the installation of expensive and complex systems.

When the Girassol and Dalia projects, on the Block 17 in Angola, were undertaken, the Operator decided to limit the number of liners for continuous injection to one.

Through this liner, a Scale and a Corrosion inhibitor will be injected at the bottom of the well. In the near future, when the water cut becomes relevant, a demulsifier could be also injected.

The liner can also be used occasionally, for the injection of methanol, in order to remove the hydrate plugs.

The paper presents the research and development undertaken to determine the different molecules (scale and corrosion inhibitors plus demulsifiers) and their compatibilities, as well as the compatibility with any other fluid that could come in contact with the additive.

The multifunctional chemical that has been especially formulated for this application, contains three different products dissolved in the same solvent, even if, generally, they are soluble in different fluids.

The advantage of such a solution is that the percentages of each of the three base compounds can be adapted to the production conditions and the evolution of the water cut, without affecting their stability.

The solution of the compatibility problems has represented a real challenge. The three active substances should not only be mutually compatible, but the product itself has to be compatible with other fluids likely to be injected through the liner. These would include methanol, used for the prevention of hydrates, or glycols, for the preservation of the liners during the shut-down periods.

The last major challenge was to obtain a stable blend presenting a very low viscosity, capable of being injected over long distances and at low temperatures with a minimum pressure drop.
Assessing the Potential of Atomic Force Microscopy to Study the Formation of Electrodeposited Calcareous Scales in Uninhibited and Inhibited Conditions
Authors: Neville A. , Bepoix M. , Graham G. , Morizot A. P.
Published: December 2007

An important feature of cathodic protection in seawater is the formation of calcareous deposits; a term, which is often used to describe magnesium (e.g. Mg(OH)2) and calcium containing (e.g. CaCO3), compounds. Deposition involves the nucleation and growth of minerals on a metallic surface from the interfacial solution, which is supersaturated with respect to certain compounds.

Electrodepostion offers a controlled method of generating surface scaling deposits and, as such, there is potential for using electrodeposition to assess the efficiency of scale inhibitors and the rate of nucleation and growth of crystals on solid surfaces.

In this study the development of scale on a stainless steel surface through application of a cathodic potential in different brine systems has been used to follow deposition of Ca- and Mg-containing compounds on the surface in uninhibited and inhibited conditions. The focus of this paper is in the potential of atomic force microscopy as a method for assessing the mechanisms and the rate of formation of scale. Some preliminary ex-situ tests were conducted to probe the kinetics of scale formation and the dependence on applied potential. Preliminary tests using in-situ AFM were conducted and some promising results are presented.
Scale and Naphthenate Inhibition in Deep-Offshore Fields
Authors: Goldszal Alexandre , Hurtevent Christian , Rousseau Guy
Published: December 2007

Many of the fields that have been discovered recently in the West African deep-offshore will produce acidic crudes associated with gas containing a high concentration of CO2.

During the oil production process, a pH increase due to decompression and carbon dioxide degassing may generate surface-active naphthenates that can drastically stabilize emulsified water in crude oil. These may also combine with metal cations present in the reservoir water and form deposits. In all cases, production operations may be seriously disturbed.

The aim of the work conducted was to assess naphthenate and scale inhibition and the various factors that can affect its efficiency. In particular, we studied scale inhibitor interactions on naphthenate prevention.

This paper presents the results of studies on emulsion stability and naphthenate deposit formation, evaluated for various acidic crudes. As the pH increased, various behaviors were observed: progressive emulsion stabilization or abrupt transitions from unstable to stable emulsions. Naphthenate deposits formed in some cases even at low pH. Such a diversity of behaviors was explained in terms of differences in acid natures.

To prevent emulsion stability and naphthenate deposits, selected demulsifier and scale inhibitor additives were then tested. Several types of demulsifiers were found to be efficient at both emulsion-breaking and naphthenate deposit inhibition. In some cases, mixtures of demulsifiers and scale inhibitors produced very good results, highlighting a synergetic effect between the two additives. Unfortunately, the use of scale inhibitors generally increased the calcium content of the oil phase. Basically, the use of scale inhibitor with acidic crudes degrades the oil quality in terms of water cut and metal content.
A Protocol to Inhibit the Formation of Natrium Chloride Salt Blocks
Authors: Kirk Joseph W. , Dobbs James B.
Published: December 2007

In many parts of the world, petroleum is produced from reservoirs, which also produce brine water that is near saturation with respect to sodium chloride salt. During the course of producing these fluids, salt crystals form and grow to a point that a "salt block" occurs in the well and/or flowlines. The mechanisms of formation vary, but most often it follows one of two scenarios: Temperature cooling, as the fluids are transported from the reservoir to the surface, causes the temperature to drop. Saturation occurs and deposition begins.Concentrating of the brine downhole as produced gas strips water, leaving the salt behind concentrating the solution of sodium chloride brine. Salt blocks occur as the deposit grows.

Laboratory testing has identified at least two types of additives that will function as a sodium chloride scale inhibitor. From this data, field applications have been designed and applied.

This paper will describe the chemical testing, the field application by three application methods, and discuss field data that illustrates successful salt block inhibition.
The Importance of Appropriate Laboratory Procedures for the Determination of Scale Inhibitor Performance
Authors: Graham G. M. , Collins I. R. , Stalker R. , Littlehales I. J.
Published: December 2007

Inhibitor performance in terms of the minimum inhibitor concentration (MIC) or the threshold concentration required to prevent scale is the most important aspect for scale control additives. The laboratory test protocols adopted throughout the industry are very similar and are based upon static "bulk" inhibition performance tests and dynamic "tube blocking" inhibitor performance tests. However it has become evident from field selection studies that performance results, obtained from different laboratories using similar techniques, can be significantly different.

In this paper the various procedural differences are described. Results are presented from an extensive series of comparative performance tests examining both static and dynamic performance against calcium carbonate and barium sulphate scale. The results clearly demonstrate how relatively small differences in test procedure, as currently adopted by different laboratories, can have a significant impact on determined MIC values and comparative performance of different species. Such procedural modifications can therefore impact upon the reliability of data obtained in field chemical selection studies and the determination of dose levels, leading to the selection of less effective products. Tests examine the comparative performance2,3 and for selecting scale inhibitor products prior impact of test procedures on generically different inhibitor species including phosphonate, polyacrylate and polyvinylsulphonate chemistries. The impact of the following aspects are covered: The inclusion of bicarbonate ions on both static and dynamic barium sulphate performance tests.The manner in which pH adjustment impacts dynamic sulphate and carbonate performance tests.Effect of flow rate, un time, coil dimensions and pre-scaling on dynamic barium sulphate and carbonate performance tests.

Significant changes in both MIC values and also product ranking are recorded using variations on the standard test protocols commonly used in different laboratories, which demonstrates that more standardised and field appropriate procedures are required. The results in terms of changes in MIC and ranking of the different products are then explained mechanistically based upon the properties of the different products and the impact of modifications to test procedures. Examples of comparative performance for particular field cases are shown which demonstrate the importance of a field appropriate procedure. Finally, recommended test protocols will be detailed based upon the findings of this study.
Water Shut-Off Treatments In Open Hole Horizontal Wells Completed With Slotted Liners
Authors: Arangath R. , Mkpasi E. E.
Published: December 2007

This paper describes a water shut-off treatment on a horizontal well in a field operated by Mobil Producing Nigeria (MPN) offshore Nigeria. The well was initially completed with an uncemented slotted liner in a highly permeable formation. The field location and pre-treatment well completion schematic are shown in Figures 1 and 2 respectively. The intervention was carried out with the use of coiled tubing through the existing production tubing string. Figure 1Location of MPN’s well XFigure 2MPN’s well X pre- treatment completion schematic.

On inception of production this well showed water cuts well above those normally expected. The high water cut, with the attendant reduction in produced oil, was not expected from a review of the geological and reservoir data of the formation. Therefore a coiled tubing conveyed production log was acquired to identify water entry points. Interpretation of the logs showed that the water was entering from a short section located approximately in the middle of the horizontal drain hole. It was observed that there was no contribution to (oil) flow below this zone, which was also found to be the deepest in the horizontal section and hence closest to the oil/water interface.

The section was therefore sealed off to increase oil production and maximize recovery from the section of the reservoir in which the well was drilled. The secondary objective was also to free the pipeline and other production facilities of this unwanted fluid (water).

A through tubing inflatable bridge plug and cement retainer were set respectively above and below the water entry section to provide a means to retard water production.

The water entry section of the horizontal wellbore was sealed off with a polyacrylamide gel. This gel was specifically tailored to seal off behind the slotted liner and prevent any flow back of polymer in the annular section that was contributing to oil flow. The treatment was performed in 3 days and the well was left closed-in for 2 days to allow the polymer to cure. The well was later reopened and it flowed spontaneously.

Post treatment production tests showed a decrease in water cut of approximately 70% while the corresponding oil gain was in excess of 25%. These figures have been maintained for at least 1 year after the treatment.

Based on these results two other similar treatments (designated as well Y and Z) have been performed for a minor operator in Nigeria. The results of these two treatments are also presented.
Coiled Tubing in High-Pressure/High-Temperature Wells—Technical Enhancements in the North Sea
Authors: Ponsonby Miles , McClellan Nick , Ligertwood John
Published: December 2007

This paper presents an overview of coiled-tubing (CT) innovations and perforating-tool enhancements that have been developed in recent years to meet the challenges of coiled-tubing perforating in high-pressure, high-temperature (HPHT) well environments in the North Sea, specifically on TotalFinaElf’s Elgin and Franklin fields.

Key areas covered include: the manufacturing and inspection of coiled tubing; new pressure-control equipment for pressures up to 15,000 psi and temperatures up to 390°F; installation, operation, and maintenance of surface equipment; downhole tools; perforating tools; elastomers; well fluids; contingencies; best practices; and future solutions.
Full-Scale Tests Prove it Practical to "Drill" Holes with Coiled Tubing Using Only Acid; No Motors, No Bits
Authors: Portman Lance , Rae Phil , Munir Antares
Published: December 2007

This paper details the results of a test program designed to show that acid can be used to construct clean, defined wellbores in carbonate rocks. The results show that with the correct choice of nozzle layout, acid strength and jetting pressure, holes can be constructed at commercially attractive rates.
Variable OD Coiled Tubing
Authors: Newman Ken , Martin John
Published: December 2007

This paper presents the concept of coiled tubing (CT) with a continuously varying outside diameter (OD) over a substantial portion of its length. Potential applications for variable OD CT (VODCT) are discussed to show why this concept is being considered. The changes required to conventional CT surface equipment to handle VODCT are discussed. Finally, possible manufacturing techniques are discussed for making VODCT.
Solutions to Coiled Tubing Depth Control
Authors: Flowers J. K. , Nessim A. E.
Published: December 2007

Evolution of coiled tubing services requires greater down-hole depth accuracy. Depth critical jobs include coiled tubing conveyed perforating, zonal isolation and plug setting, among others.

Coiled tubing depth measurements are performed at surface, using devices to measure the length of coil tubing being deployed in the well. Measurement methods and their procedures have varied over time and have been continuously developed and improved on in an attempt to achieve higher degrees of accuracy and reliability in the length measurement. By principle, these methods provide a measurement of the length of the pipe deployed into the well but may considerably differ from the true depth of the coil end due to down-hole deformation of the coil tubing.

Various factors influence the down-hole deformation of the coil tubing; among these factors are temperature and pressure effects on the pipe. Elastic deformation of the pipe due to its own weight, sinusoidal and helical buckling effects occur and can substantially affect true depth. In view of this complexity, down-hole depth correlation is executed in depth critical jobs using various techniques, such as; tubing end locator, wireline logging tools, memory runs and reference depth tagging technique.

This paper discusses the different methods of surface pipe length measurement, their historical developments and the errors in true depth from measured depth due to down-hole deformation of the coil tubing. We present the results of a newly developed tool, DepthLOG, that provides a reliable and accurate down-hole depth correlation without the drawbacks and expense of other currently used down-hole depth correlation runs.
Cost Reduction and Injectivity Improvements for CO2 Foams for Mobility Control
Authors: Grigg Reid B. , Tsau Jyun-Syung , Martin F. David
Published: December 2007

This paper identifies chemical cost reduction derived from the synergistic effects of co-surfactant systems using a good foaming agent and a less expensive poor foaming agent. The required good foaming agent is reduced by at least 75%. Also the effect on injectivity is reduced by as much as 50% using the co-surfactant system, compared to a previously used surfactant system. Mobility control of injected CO2 for improved oil recovery can be achieved with significant reduction in the chemical cost of SAG, improved injectivity of SAG, and improved economics of CO2 injection project when compared to reported systems.
New Insight on Polymer Adsorption Under High Flow Rates
Authors: Chauveteau G. , Denys K. , Zaitoun A.
Published: December 2007

In previous papers we investigated high-molecular-weight polyacrylamide adsorption under high shear rates in low-permeability media and found that, above a critical value γc, adsorbed macromolecules can reduce the permeability by factors over hundred, suggesting a mechanism of pore throat bridging. New lab experiments have been designed specifically to elucidate the mechanism at the origin of this "bridging adsorption". Polymer injections were carried out over a wide range of shear rates in homogeneous high-permeability granular packs having hydrodynamic pore throats too large to be bridged by polymer macromolecules. When polymer is injected at low shear rate (γ < γc) the adsorbed layer thickness εHS (calculated from permeability reduction values) does not depend on injection rate. When the injection occurs at higher shear rates (γ > γc), εH increases slowly up to reach maximum values εHM increasing with injection shear rate. These εHM values were found to be large enough to explain the very high reductions in permeability obtained previously in low-permeability packs.

These results show that polymer adsorption in porous media can be increased significantly by the hydrodynamic forces normal to the pore wall, as soon as they become high enough to "push" additional macromolecules into the already adsorbed polymer layer. This mechanism increases both polymer adsorption density and adsorbed layer thickness. We propose to refer to this mechanism as a "flow-induced adsorption". This new interpretation is consistent with all results previously attributed to "bridging adsorption" and the new results reported in this paper. It provides an important conceptual tool to model polymer placement in water shutoff and to design conformance treatment.
Time-Dependent Shape Factors for Interporosity Flow in Naturally Fractured Gas-Condensate Reservoirs
Authors: Penuela G. , Civan F. , Hughes R. G. , Wiggins M. L.
Published: December 2007

A rigorous interporosity flow equation incorporating a time-dependent shapefactor is derived and validated for improved dual-porosity modeling ofnaturally fractured gas-condensate reservoirs. The equation expresses theinterporosity molar rate in terms of the pseudo-pressure gradient in thematrix, fracture surface area, matrix permeability, and a variable matrix-blockshape factor. This approach can accommodate the flow directed from matrix tofractures in a simulator that represents the permeability of the interconnectedfractures by a tensor inside each grid-block. This feature distinguishes thismodel from the popular sugar-cube approach to modeling naturally fracturedreservoirs.

Compositional simulation is performed to verify the flow equation using thetime-dependent shape factor. Numerical experiments with various matrix-blocksizes indicate that the shape factor varies with time but converges to valuesderived by Lim and Aziz (1995). The average matrix-pressure location in thematrix block shifts from near the fracture face to the block center as thefluid flows from the matrix into the fracture. This phenomenon indicates thatneglecting the time dependency of the shape factor can introduce significanterrors in numerical simulation of naturally fractured reservoirs. The timedependency can contribute significantly to fluid production once the pressurefront moves through the reservoir along the highly permeable fracture network.This phenomenon is not considered in present commercial simulators that usepseudo-steady state factors.

The model equations are expressed in dimensionless form so they can bereadily integrated into current simulators. The dimensionless time used in theproposed method includes pseudo-functions that capture multiphase effects ofthe gas-condensate systems. Applications to single- and multiphase black-oilsystems are also discussed.
A New Method of Calculating Reservoir Pressure in Real Time
Authors: Foo David
Published: December 2007

Real-time data contains a record of the producing conditions in a well. This data is used for production reporting but is seldom used directly to analyze production problems. In fact, to fully realize the value of real-time data, new analysis techniques need to be formulated.

Part of the problem with using real-time data relates to the nature of conventional production engineering methods. Accepted techniques attempt to model well behavior using steady-state behavior, when in fact well behavior is constantly changing. Conventional nodal analysis uses a "snapshot" of data, taken at a single moment in time, which may or may not be representative of the well's behavior.

Real-time data, on the other hand, presents the unsteady-state behavior of a well, reflecting the subtle variations in all aspects of the production system (including flowlines and facilities). However, the equations for unsteady-state analysis are generally very complex and impractical for day-to-day analysis.

In investigating the best approach for using real-time data to analyse well problems, methods of combining time-based data with steady state analysis techniques were examined. From this work, a new method for calculating reservoir pressure from wellhead data was discovered. This method does not require any knowledge of cumulative production or initial reservoir pressure, but yields a result that can be within 5% of that measured by performing a buildup test. Advantages of this method include: Normal day-to-day flow data is used, so the well does not need to be shut in to gather data.Results are available immediately.The method is simpler both mathematically and logistically.The data required is gathered as a part of mandatory production reporting, so historical data can yield the reservoir pressure at any point in the well's past.

This paper presents the method developed for calculating reservoir pressure from SCADA data. Several real world examples are presented, limitations of the method are reviewed, and further enhancements are discussed. Most importantly, this paper highlights the value available through analyzing the real-time data acquired by SCADA systems.
Numerical Simulator Comparison Study for Enhanced Coalbed Methane Recovery Processes, Part I: Pure Carbon Dioxide Injection
Authors: Law David H.-S. , van der Meer L. G. H. , Gunter W. D.
Published: December 2007

The injection of carbon dioxide (CO2) in deep, unmineablecoalbeds can enhance the recovery of coalbed methane (CBM) and at the same timeit is a very attractive option for geologic CO2 storage asCO2 is strongly adsorbed onto the coal.

Existing CBM numerical simulators which are developed for the primary CBMrecovery process, have many important features such as: (1) a dual porositysystem; (2) Darcy flow in the natural fracture system; (3) pure gas diffusionand adsorption in the primary porosity system; and (4) coal shrinkage due togas desorption; taken into consideration. However, process mechanisms becomemore complex with CO2 injection. Additional features such as: (1)coal swelling due to CO2 adsorption on coal; (2) mixed gasadsorption; (3) mixed gas diffusion; and (4) non-isothermal effect for gasinjection; have to be considered.

This paper describes the first part of a comparison study between numericalsimulators for enhanced coalbed methane (ECBM) recovery with pureCO2 injection. The problems selected for comparison are intended toexercise many of the features of CBM simulators that are of practical andtheoretical interest and to identify areas of improvement for modeling of theECBM process. The first problem set deals with a single well test withCO2 injection and the second problem set deals with ECBM recoveryprocess with CO2 injection in an inverted five-spot pattern.
Simplified Correlations for Hydrocarbon Gas Viscosity and Gas Density – Validation and Correlation of Behavior Using a Large-Scale Database
Authors: Londono F. E. , Archer R. A. , Blasingame T. A.
Published: December 2007

The focus of this work is the behavior of gas viscosity and gas density for hydrocarbon gas mixtures. The viscosity of hydro-carbon gases is a function of pressure, temperature, density, and molecular weight, while the gas density is a function of pressure, temperature, and molecular weight. This work presents new approaches for the prediction of gas viscosity and gas density for hydrocarbon gases over practical ranges of pressure, temperature and composition. These correlations can be used for any hydrocarbon gas production or transportation operations.

In this work we created an extensive database of measured gas viscosity and gas density (>5000 points for gas viscosity and >8000 points for gas density). This database was used to evaluate existing models for gas viscosity and gas density. In this work we provide new models for gas density and gas viscosity, as well as optimization of existing models using this database.

The objectives of this research are: To create a large-scale database of measured gas viscosity and gas density data which contains all of the in-formation required to establish the applicability of various models for gas density and gas viscosity over a wide range of pressures and temperatures.To evaluate a number of existing models for gas viscosity and gas density.To develop new models for gas viscosity and gas density using our research database — these models are proposed, validated, and presented graphically.

For this study, we created a large-scale database of gas properties using existing sources available in the literature. Our data-base includes: composition, viscosity, density, temperature, pressure, pseudoreduced properties and the gas compressibility factor. We use this database to evaluate the applicability of the existing models used to estimate hydrocarbon gas viscosity and gas density (or more specifically, the z-factor). Finally, we provide new models and calculation procedures for estimating hydrocarbon gas viscosity and we also provide new optimizations of the existing equations-of-state (EOS) typically used for the calculation of the gas z-factor.