bluuebunny/crossref_metadata_2025 huggingface dataset:
A General Purpose Controller for Coupling Multiple Reservoir Simulations and Surface Facility Networks
Authors: Ghorayeb Kassem , Holmes Jonathan , Torrens Richard , Grewal Balraj
Published: December 2007

Integrated surface-subsurface modeling has been shown to have a critical impact on field development and optimization. Integrated models are often necessary to analyze properly the pressure interaction between a reservoir and a constrained surface facility network, or to predict the behavior of several fields, which may have different fluid compositions, sharing a common surface facility. The latter is gaining a tremendous significance in recent deepwater field development.

These applications require an integrated solution with the following capabilities: To balance a surface network model with a reservoir simulation model in a robust and efficient manner.To couple multiple reservoir models, production and injection networks, synchronising their advancement through time.To allow the reservoir and surface network models to use their own independent fluid descriptions (black oil or compositional descriptions with differing sets of pseudo-components).To apply global production and injection constraints to the coupled system (including the transfer of re-injection fluids between reservoirs).

In this paper we describe a general-purpose multi-platform reservoir and network coupling controller having all the above features. The controller communicates with a selection of reservoir simulators and surface network simulators via an open message-passing interface. It manages the balancing of the reservoirs and surface networks, and synchronizes their advancement through time. The controller also applies the global production and injection constraints, and converts the hydrocarbon fluid streams between the different sets of pseudo-components used in the simulation models. The controller's coupling and synchronization algorithms are described, and example applications are provided. The flexibility of the controller's open interface makes it possible to plug in further modules (to perform optimization, for example) and additional simulators.
A Generalized Wellbore and Surface Facility Model, Fully Coupled to a Reservoir Simulator
Authors: Coats B. K. , Fleming G. C. , Watts J. W. , Ramé M. , Shiralkar G. S.
Published: December 2007

The formulation of a black oil or compositional fully coupled surface and subsurface simulator is described. It is based on replacing the well model in a conventional reservoir simulator with a generalized network model of the wells and facilities. This allows representation of complex wellbore geometry and downhole equipment. The global reservoir/network system is solved simultaneously at the end of each simulator Newton iteration. The method avoids inefficiencies of other coupled models in which wells and facilities are treated as separate domains, or in which the global system is not solved simultaneously. Example cases demonstrate the efficiency of the model for cases with simple and segmented wellbores, with and without facilities.
Intergrid Operations - Dynamic Gridding Techniques in Nonlinear Domain Decomposition Methods
Authors: Liu Wei , Mezzatesta Alberto G. , Hildebrand Margaret A.
Published: December 2007

Domain decomposition methods provide major advantages to large-scale and high-resolution reservoir simulation studies in terms of computer resource requirements. In this paper, a directional, intergrid mapping technique is introduced together with a nonlinear domain decomposition algorithm - the Fast Adaptive Composite Grid (FAC). Domain decomposition techniques have often been applied to solve the linear system of equations resulting from reservoir numerical models. However, a stronger, more efficient approach is to apply the domain decomposition techniques directly to the nonlinear problem. As a result, mapping dynamic reservoir properties from one grid scale to another one, a process also known as intergrid mapping, becomes a key operation in dealing with composite grid systems.

Normally, upscaling and downscaling techniques focus on geological structures and formation properties. The proposed intergrid mapping operations in the FAC method honor the static reservoir properties while preserving the properties of fluid flow dynamics between grids with different scales. Most importantly, the intergrid mapping operator in FAC can accurately represent local phenomena in much coarser domains, so that the composite grid residual, which can be viewed as the relative overall solution error, can be effectively minimized. Application of the FAC method brings significant reduction in CPU time and memory requirements when compared with simulations having the same level of global grid and timestep refinement, making it possible to attain large simulation scales and resolution with limited computer resources.

In this paper, the approximation of the differential conservation equations is based on the control volume approach and uses cell-centered finite difference methods. The composite grid solution is obtained through a defect-correction process of refinements. Unlike many domain decomposition algorithms, the proposed method provides full approximation storage (FAS) by computing and storing the whole coarse grid solution, including the grids for which a refinement exists.

Computational results from a model featuring local spacetime refinements are presented to illustrate that a rigorous intergrid mapping operation can significantly improve the efficiency of nonlinear domain decomposition algorithms, especially in cases of multiphase flow with irregular local timestepping. The presented numerical examples demonstrate the applicability of the proposed numerical method.
The Disc Bit – A Tool for Hard Rock Drilling
Authors: Placido J. C. R. , Friant J. E.
Published: December 2007

This paper traces the development of a radically different design of drill bit; its concept, laboratory work and the latest field trials are described.

The technology of the Disc-bit is based upon the single rolling disc cutter. This type of cutter was successfully used in rock for the first time on a tunnel boring machine in 1956. By the early 1970's, virtually every rock tunneling machine in the world had moved from picks, tungsten carbide button cones, or multi-row tapered cutters, to the single row disc. By then, the superior performance on tunneling machines had been demonstrated by practical experience in the field. Further, Colorado School of Mines (CSM) began scientific studies, and based on full scale laboratory testing, published data comparing the Specific Energy of Excavation of various tools. This clearly showed that the single row disc cutter required less energy to excavate a given volume of rock. With energy at the cutting face always a limited commodity, a lower energy requirement translated to higher penetration rate.

Not until the mid 1990's was the concept of the single rolling disc cutter applied to drill bits. Very small, 3 ¼" Mini-DiscTM cutters were evaluated at CSM and found to be extremely efficient and sufficiently robust to be used on drill bits as small as 7 7/8". The U.S. Gas Research Institute sponsored an effort to develop the concept by laboratory and field testing. Other field trials were sponsored by private and government grants including the most recent test funded by a JIP, managed by PETROBRAS. An evaluation of an 8 ½" Disc-Bit was performed at GRI Catoosa Test Facility, in Oklahoma, USA.
Deploying Dual Gradient Drilling Technology on a Purpose-Built Rig for Drilling Upper Hole Sections
Authors: Judge Robert A. , Thethi Ricky
Published: December 2007

The benefits of using dual gradient drilling (DGD) technology to drill complete wells in ultra-deep waters have been stated in several papers and industry presentations. However, a new opportunity to employ DGD to reduce overall drilling costs exists by concentrating on drilling upper hole sections. The support equipment, rig integration strategies, and deployment methodologies for using DGD in a "top-hole" configuration can differ significantly from a pure, full-function DGD implementation.

Risk associated with equipment failure is one hurdle that must be overcome before the use of DGD becomes commonplace in the industry. While laboratory and full scale prototype tests have been performed for several DGD system designs, full industry acceptance of the equipment and techniques may not be achieved until there is additional field experience to fall back on. One way to mitigate this risk is to develop strategies to run new equipment separate from the conventional riser. Doing so minimizes the round trip time required to pull the hardware and perform any equipment repairs that become necessary.

This paper presents options for integrating and deploying DGD equipment specifically for use in drilling upper hole sections. Included are discussions regarding the following: Deploying equipment before BOPs are setSetting equipment off to the side of the wellhead, with and without a dual activity rigDeploying equipment with a Multi-Service Vessel (MSV)Auxiliary equipment, such as a lightweight mini-riser or free-standing riser with subsea jumpers.

Utilizing this paper as a guide, operators and drilling contractors will be able to consider new field development strategies that include DGD, while minimizing the risk and expense normally associated with new technology deployment.
Field Evaluation of a Rotating Separator as an Alternative to Shale Shakers
Authors: Saasen A. , Botnmark K. , Mikalsen K. , Jensen O. D. , Dale J. F.
Published: December 2007

Occupational hygiene requirements for operations on the Norwegian continental shelf when drilling with oil based drilling fluids, favour the use of enclosed system for solids control. Personnel working with shale shakers are often exposed to a base oil mist and vapour at an unacceptable level. A concept using rotating separators as an alternative to shale shakers was developed to reduce this exposure. Drilling fluid with cuttings from the mud line is fed into a slowly rotating separator that forces the cuttings to move over a very large effective screen area with screens of selected sizes. The drilling fluid is efficiently removed from the cuttings since the area underneath the screen is slightly vacuumed. The improvements this treatment has on the occupational hygiene and the environmental impacts compared to use conventional shakers are illustrated.

The current paper focuses on a field test where the rotating separator efficiency was compared with the efficiency of conventional shakers while drilling. The drilling operation was conducted with both water based and oil based drilling fluids. The field tests are described in detail. An efficient, but still gentle separation of drilled cuttings from the drilling fluid was observed. The paper discusses if the rotating separator managed to produce proper cuttings dryness even though 60–100% of the total cuttings load produced by the drilling rig was directed through the rotating separator. After completion of the field tests, the separator was brought onshore for further improvements. The flow capacity was increased with more than 100% based on these improvements.
Uniquely Engineered Water-Base High-Temperature Drill-In Fluid Increases Production, Cuts Costs in Croatia Campaign
Authors: Soric Tomislav , Huelke Robert , Marinescu Pavel
Published: December 2007

Along with exorbitant costs and safety considerations, drilling in a high-temperature, high-pressure (HTHP) environment also poses the difficult challenge of protecting a reservoir that is all-too-often depleted. In areas where environmental restrictions and compatibility issues in gas fields prohibit the use of an oil-base drilling fluid, engineering a water-base fluid system that is free of potentially damaging solids, stable at very high temperatures, and able to withstand acid gases (CO2, H2S) or other contaminants is a very difficult proposition. The demands are compounded dramatically when drilling a deviated or a re-entry deviated slim hole well in an HTHP environment. Furthermore, since pressure and temperature heavily influences the rheological behavior, it is extremely difficult to calculate, predict and control pressure losses, ECD, and/or ESD in real time to avoid total losses or kicks.

This paper details the design of a unique water-base reservoir drill-in fluid and its successful application on five HTHP wells in the Kalinovac and Molve gas fields of Croatia. Four of the wells were high-angle re-entry slim holes. Using laboratory, field, reservoir investigation and computer data, the authors will demonstrate the effectiveness of the new fluid in delivering zero skin damage and subsequently higher production rates than other wells in the field. Further, the system significantly reduced operating costs by eliminating costly stimulations, while simplifying the generation of clear imaging logs. The system also remained stable at bottom hole temperatures of 180 – 200°C.

During the drilling operations, a unique software program was employed that accurately predicted the rheological behavior, pressure losses, ECD and ESD, which contributed heavily to the wells being drilled trouble-free. The authors will detail the formulation of the new system, along with the coordination and pre-planning that contributed to its success in Croatia. The new water-base system has shown the effectiveness in drilling HTHP wells in areas where invert-emulsion drilling fluid systems are prohibited.
Low Risk/High Reward Strategy Drives Underbalanced Drilling Implementation in PDO
Authors: Francis P. A. , Davidson I. A. , Harthi S. , Geldof W. , Culen M. S. , Jenkins T.
Published: December 2007

Underbalanced Drilling (UBD) is a drilling technology capable of delivering substantial increases in initial well productivity and ultimate recovery from oil and gas wells, as well as a host of other benefits. Petroleum Development Oman (PDO) is exploiting a variety of reservoir types that could benefit from this technology. The difficulty in assessing the performance of a well drilled underbalanced compared to a conventional (overbalanced) well, however, is compounded by reservoir heterogeneity such that even two conventionally drilled wells relatively close together may deliver substantially different well initials. Single well trials of UBD in the past in PDO have been expensive, in terms of the relative cost of mobilising equipment to the Arabian Peninsula, and the results inconclusive. A strategy of ‘Zero Cost Implementation’ was formulated to avoid these problems. The business benefits necessary to ‘pay’ for the increased cost of UBD were determined. As the risk of those returns not being met were low then a sufficiently long campaign of UBD could be justified to assess the benefits. The result of this policy was the implementation of one and a half string years of UBD (some 20 wells) in two fields (one carbonate, one clastic), which makes it one of the largest campaigns of UBD outside North America. Two UBD packages have been employed from two different contractors and the campaign started in May 2002. Not only have both projects delivered significant increases in productivity but they have also shown the benefits of real-time assessment of reservoir productivity while drilling allowing real-time decisions on well operations and completion design.
The Transfer of Through Tubing Drilling (TTD) Technology Between Provinces
Authors: Morrison John W.
Published: December 2007

Many companies operate on a global basis. Often a new idea or technology can make a step-change in the economics, or performance, in a particular province or field. That leaves the company with the enviable problem of understanding how and where it could impact its operations in other areas of the world.

One area where bp has had such success is in the North Slope of Alaska, where TTD has made a dramatic impact on their infill-drilling programme. In fact, Alaska had developed two distinct TTD techniques, Coiled Tubing Drilling (CTD) and Through Tubing Rotary Drilling (TTRD). This paper discusses how we transferred the technology to the North Sea. The subject is tackled on three levels: Transfer of practical knowledgeThe tactical choice on the optimum techniqueDetermination of the strategic value of the technology

It illustrates what needs to be done to ensure a successful business outcome when trying to gain the benefits of a new technology, but in a different operating environment.

To illustrate the issues, the paper will present performance information on both TTD techniques used in Alaska. It will talk about their differences, and why the application of CTD, in particular, has made such a significant impact. It will then discuss how the North Sea operating environment differs from the North Slope, how this influenced the choice of technology and the potential magnitude of the benefit that could be realised.

By the end of the analysis, it became clear that the solution and strategy for the North Sea had to be different from that of Alaska. It also makes it apparent why CTD has struggled to make an impact in the North Sea.
Northstar Drilling - A Progressive Arctic Endeavor
Authors: Kidd Gavin N. , Holt Barbara M.
Published: December 2007

So what is it that makes the Northstar Development stand out among all other drilling operations on the North Slope? Certainly the size, location and access are the three most obvious aspects of the project. Drilling an 8400-acre oilfield from a 3.7-acre manmade island 6 miles out in the Beaufort Sea has presented some distinctive challenges. Many of these challenges were anticipated and addressed, while many others were not. Despite the unique backdrop of such an extreme location, Northstar is a great example of how Beyond the Best principles have been applied. From FEL (Front End Loading) to execution and implementation of the Technical Limit Process, the Northstar team employs proven processes to strive for performance that is truly beyond the best. New technologies have been applied, along with the learning's from GPB (Greater Prudhoe Bay), to great effect. The paradigm of Northstar is such, that without a coordinated approach by all functions of the project, from Facility engineering, reservoir management, logistical support, construction engineering to drilling, the project would have failed. With aligned goals, determination and excellent attitudes, Drilling has consistently produced best in class performance. This paper explores the Northstar paradigm in more detail, along with the logistical details of supplying for an accelerated Drilling Program during seasonal restrictions in a lay-down area equivalent to 50% of a football field.
Drillstring With Aluminum Alloy Pipes Design and Practices
Authors: Gelfgat Mikhail Ya. , Basovich Vladimir S. , Tikhonov Vadim S.
Published: December 2007

The up-to-date aluminum drill pipes design made it possible to develop ultra-long drillstrings for super-deep and extended reach wells. The new generation software providing for drillstring analysis including consideration of drillpipe tool joints and pads in buckling helical loads evaluation. Drill string dynamics is also taken into account. The case studies of ADP application proved their benefits over the steel ones, and recent analysis have shown an opportunity to design a super-long 15,000 m well and this was not the absolute limit.
Riserless Drilling Performance in a Shallow Hazard Environment
Authors: Roller P. R.
Published: December 2007

Riserless drilling has become an increasingly important aspect of deepwater operations. This is particularly true when drilling in areas with shallow gas and shallow water flow potential.

The following paper highlights the operational pre-planning and successful results of drilling a deepwater prospect with both known and un-known shallow hazards. The aspects of drilling fluid and supply vessel management along with its relationship to the successful operation will be addressed in detail. The documented results of this project should reinforce the importance of emergency preparedness in all types of well operations.
Multilateral Technology Coupled with an Intelligent Completion System Provides Increased Recovery in a Mature Field at BP Wytch Farm, UK
Authors: Redlinger T. , Constantine J. , Makin G. , Glaser M. , Brown C. , Cooke D. , McLaughlin J.
Published: December 2007

Exploiting proven technology, improving functionality and adding intelligent completions, create an intelligent level 4 multilateral junction ideal for offering commingled, isolated, or deferred production. The junction offers re-entry access to the lateral and a low risk installation.

This intelligent multilateral installation should pay for the completion and drilling of lateral to new target zone in estimated "saved" revenue from the mainbore, which is normally lost in a traditional sidetrack.

The TAML level 4 junction was built around the proven concept of a hollow whipstock. The hollow whipstock technology has been significantly improved allowing for high-pressure capability before and after milling the window. An innovative concave geometry protects the concave face from milling process. After drilling the lateral, the liner is installed and cemented across the junction. The hollow whipstock and liner are perforated to regain production. Selective isolation is then achieved through an intelligent sliding sleeve completion system.

The all-hydraulic intelligent completion system combines several new and existing technologies. A downhole hydraulic logic unit was run which minimized the number of surface control lines whilst allowing individual flow control devices to be addressed from surface. The logic unit also controlled the setting of the production packers. Hydraulic flow controls were included to allow selective isolation without intervention of the producing intervals.

Shortly after the completion installation the flow control devices were activated resulting in the avoidance of a probable ESP workover.

Results:

This is the case history of the first intelligent TAML Level 4 multilateral installation at Wytch Farm. It will highlight the drivers that led to selecting multilateral and completion configurations, illustrate the installation sequences, and comment on continuous improvement efforts to ensure future successful installations of this technology.
Real-Time Web-Based Data Delivery Improves Drilling Efficiency in Deepwater: Thunder Horse - A Case Study
Authors: Looney B. , Alvarado R. J. , Essawi A. , Will M.
Published: December 2007

Real-time Web-based data delivery is now available for monitoring drilling processes. This paper demonstrates how both drilling decisions and workflow can be improved through effective use of this real-time collaboration tool. The examples are from the Thunder Horse deepwater project in the Gulf of Mexico.

As a first example, lateral vibration problems, which could have led to tool failures and an expensive trip out of the hole, were first detected in the office by an expert who was monitoring the operations using the Web-based data delivery system. An expert drilling team was then assembled in the office to collaborate with the rig personnel using the Web tool. The virtual rig-office team experimented with drilling parameters such as surface revolutions per minute (RPM) and weight on bit (WOB). The Web system provided instantaneous feedback from the rig showing the effects of these changes. The team was able to develop a vibration-minimizing solution, saving more than $400,000 for a trip. Furthermore, the team solved the problem in far less time than would have been possible without the data delivery system.

Other examples include real-time leakoff test monitoring, real-time density image analysis, and integration of real-time data from different sources on the rig, including gas and lithology data. This paper shows how the Thunder Horse team developed a novel workflow for deepwater operations, leveraging real-time Web-based data delivery to facilitate remote, team-based decision making and dramatically improve drilling efficiency.
Directional Drilling with Casing
Authors: Warren Tommy , Houtchens Bruce , Madell Garret
Published: December 2007

Drilling with casing has proven to be an effective method of reducing drilling costs and solving drilling problems. Most of the current Casing Drilling* activity is focused on drilling vertical wells, but interest in directional wells is increasing as the benefits of Casing Drilling in straight holes are demonstrated.

A directional Casing Drilling system has been run sufficiently to prove that directional drilling with casing can be practical with casing sizes from 5-1/2" to 13-3/8". The system uses a wireline retrievable directional drilling assembly, positioned in the lower end of the casing, to replace the conventional directional tools used when drilling with drill pipe. These tools have been used to drill to inclinations greater than 90° and have been retrieved and re-run at inclinations ranging from vertical to horizontal.

The directional Casing Drilling system can be used for a broad range of directional applications to capture the proven advantages of Casing Drilling that have been demonstrated for vertical wells.
Non-Selective Placement of a Polymer Gel Treatment to Improve Water Injection Profile and Sweep Efficiency in the Lagomar Field, Venezuela
Authors: Romero C. , Marin A. B. , Candiales L. E. , Mejias O. J. , Romero E. J. , Angulo R. J. , Flores E. , Norman C.
Published: December 2007

Results of polymer gel treatments in injection wells, suggest worldwide that there is a positive correlation between larger gel volumes and resulting incremental oil production in offset producing wells1–5. However, gel placement procedures, particularly in matrix (unfractured) reservoirs, remain a source of controversy. Many operators heavily rely on the permeability contrast in heterogeneous matrix reservoirs to assure the correct placement of the gel treatment, claiming that polymer gels will not penetrate and damage lower permeability zones to any significant degree. However, other studies indicate that in a matrix environment, the gel will enter any layer(s) that is not mechanically isolated during the gel injection, risking damage to "unprotected" zones. This paper presents PDVSA's experience in Venezuela with a polymer gel treatment that was placed without mechanical isolation into an injector in the Lagomar Field with positive results. This layered reservoir, characterized as highly heterogeneous, has been under waterflood for over 4 decades and currently, high water cuts are affecting its production and forcing the closedown of production wells in the area. In this work we include new evidence that might explain why this placement technique has been successful in this originally "unfractured" reservoir. In this new analysis, geological and geomechanical features are revised as part of the diagnosis, in order to determine the low sweep efficiency problem, and this information is used to aid in the injection strategy planned for the well.

Results from the treatment were evaluated with Production logging tools (PLT) run before and after the treatment, showing the blockage of the thief zones and redirection of injection water to lower permeability zones. A total of 3700 bbls of gel were injected and response in two associated producers was observed 5 months after the treatment with an average reduction of 30% in the water cut and 26,850 bbls of incremental oil.
Comparative Study of Different Silicone Compounds as Candidates for Restriction of Water Production in Gas Wells
Authors: Lakatos I. , Tóth J. , Bauer K. , Lakatos-Szabó J. , Palásthy Gy. , Wöltje H.
Published: December 2007

The paper demonstrates both converging and controversial laboratory results in potential application of silicone compounds (silanes, siloxanes and silicone oils and resins) to be used for restriction of water production in gas wells. The research program was extended to determination of surface and colloid chemical, rheological, hydrodynamic and retention properties of silicone-containing fluids in natural and synthetic porous media. Special attention was paid to the effect of different silicones on absolute, effective, relative and normalized relative permeability, and capillary and normalized capillary pressure curves. The complex survey has clearly shown that some silicone compounds, particularly in low permeable, tough porous media, drastically change the capillary forces, the spontaneous imbibition rate, and hence they offer a special option for delay of water break-through in gas/water systems. The comparison of different silicones provided sufficient information for development of a new technology which has been tested under field condition for restriction of water production in a tough, low permeable gas field (Algyő field, Hungary).
Development of a Hydrophobically Modified Water-Soluble Polymer as a Selective Bullhead System for Water-Production Problems
Authors: Eoff Larry , Dalrymple Dwyann , Reddy B. R. , Morgan Jim , Frampton Harry
Published: December 2007

For many years, bullhead systems have received a great deal of attention from the oil and gas industry. Because of the completion techniques used in many wells, protecting the hydrocarbon interval effectively during a water control treatment is not always practical or cost-effective. Bullhead systems offer the option of a treatment without zonal isolation and are designed to decrease water production with little or no decrease in oil or gas production. This paper describes the laboratory development of a new polymer that shows promise as a bullhead system.

The material falls into the class of hydrophobically modified water-soluble polymers; that is, a water-soluble polymer into which water-insoluble moieties have been introduced. The unique associative and adsorptive properties of this class of polymers are well documented, but they have not been commercially exploited to a great extent in oil field applications.

These materials offer improvements over the hydrophilic polymers traditionally used for permeability modifications. For example, hydrophobic modification appears to improve cleanup of the polymer that penetrates an oil saturated core, resulting in less risk of damage to oil permeability. Hydrophobic modification, depending on the structural features, also increases reduction to water flow in comparison to the unmodified polymer. This paper includes a general description of hydrophobically modified polymers and their properties, as well as detailed descriptions of the development and laboratory testing of the new system.
Application of Water-Based and Oil-Based Aphrons in Drilling Fluids
Authors: Growcock Frederick B. , Khan Asif M. , Simon Gerard A.
Published: December 2007

Aphrons are specially stabilized micro-bubbles created in situ to aid in suppressing the loss of drilling fluid into high-permeability formations. Water-based aphrons are designed for aqueous drilling fluids, while oil-based aphrons are designed for non-aqueous fluids. In both cases, the micro-bubbles are composed of a core of gas or liquid stabilized by proprietary polymers and surfactants, which can aggregate to form a tough, elastic barrier to loss of drilling fluid in permeable zones. Some of these zones are typified by water-wet sands that are susceptible to fluid seepage and differential sticking. Others are characterized by laminated sand and shale sequences, which are expensive to drill with conventional drilling fluids or underbalanced drilling rig equipment.

The authors describe how use of water-based and oil-based aphrons in drilling fluids can mitigate losses of drilling fluids downhole.
Application of an Ammine-Complex Adsorption Technique as an Alternative to Dielectric Constant Measurements (DCM) for Offshore Shale Typing
Authors: Sanders M. W. , Stewart J. , Tavendale F. M. , Abernethy R. H. , McCurdy P.
Published: December 2007

Dielectric Constant Measurements (DCM) are often a significant component of field wellbore stability studies. The DCM technique is a recognised method for characterizing clay material, providing good correlation between specific surface area measurements and rock strength. The most accurate methodology is to characterize intra-reservoir shale whilst drilling. A portable DCM instrument can be used offshore; unfortunately such units cannot always be made available.

Previous work has suggested a correlation exists between DCM specific surface area measurements and methylene blue titration (MBT) cation exchange results. However, a number of concerns were raised over the relative accuracy of the technique, and more importantly, on the consistency of testing between engineering personnel. Hence, an alternative, more quantitative method for accurately and rapidly determining the cation exchange capacity (CEC) of shale was required.

A method, first proposed by Bardon et al.,1 based upon the interaction of ammine-transition metal complexes with the clay exchange sites, was selected and adapted for use offshore. The reactivity of the clay material could then be determined colorimetrically based upon cobalt hexammine trichloride depletion. This method was applied in an actual field situation.

The Nelson field is located on the Forties-Montrose High within the Central Graben, UK Central North Sea, and some 113 miles east of Aberdeen. The reservoir, an oil producer, consists of submarine fan sands of the Forties Formation at approximately 7,200 feet TVDSS (true vertical depth sub sea). Serious problems were experienced with intra-reservoir shale while drilling the1 near-horizontal 8 1/2-inch section of Nelson well 22/11-N30y. Intra-reservoir shales were prognosed on a subsequent well, 22/11-N32 of similar trajectory. In order to minimise drilling risks, a full wellbore stability study was conducted. The ammine-complex adsorption test was used offshore, in place of DCM, to determine shale reactivity as part of a ‘shale type risk assessment matrix’ developed from this study.

A good correlation between specific surface area measurements and cobalt hexammine complex adsorption was found, providing a viable alternative to offshore DCM measurements for shale characterisation. It is believed by the authors that this is the first time this particular technique has been used in the field for this application.
The Chemistry of Formate Brines at Downhole Conditions
Authors: Javora Paul H. , Ke Mingjie , Stevens Richard F. , Berry Sandra L.
Published: December 2007

Sodium, calcium and zinc bromide and chloride brines have been used successfully as clear completion and packer fluids for more than 20 years, and their chemistry and applications have been evaluated and reported. Sodium, potassium and cesium formate brines are relatively new brines being explored for use as clear completion and packer fluids. However, relatively little information has been published about their chemistry in oilfield usage, especially under hostile conditions of temperature and CO2 environments. This paper describes the chemistry of formate brines used in the oilfield not previously published.

Extensive research and laboratory data was developed to understand the effects of pH, buffer capacity, CO2 content and temperature on the corrosion potential and decomposition of formate brines. Results from thermal stability testing and corrosion testing are presented which identify conditions for thermal decomposition of the formate ion and conditions for significant corrosion of oilfield tubulars at typical downhole conditions. Conditions for hydrogen gas generation, carbon monoxide gas formation, scale formation and corrosion potential are described. Understanding the results derived from this work could be critical to the selection of formate brines used for downhole conditions.
Unusual Oilfield Corrosion Inhibitors
Authors: Martin Richard L.
Published: December 2007

This paper summarizes a laboratory study of unusual corrosion inhibitors subjected in kettle tests to conditions that might exist in the oilfield. Some corrosion inhibitors are compounds with another primary function. Quaternary ammonium compounds are in this group; the primary function is often biocidal but under the right conditions, substantial corrosion inhibition is observed. Tetrakishydroxymethyl phosphonium sulfate (THPS) is another compound frequently used for its biocidal properties. Under certain conditions THPS is a corrosion aggravator, under others it is an effective inhibitor.

Calcium ions alone are not corrosion inhibitors. However, some inhibitors are considerably more effective when calcium is present in the corrosive brine. Some inhibitor/corrosive systems are not influenced. This system was examined for trends.

Other unusual corrosion inhibitors are tabacco extract and molasses. These materials were examined earlier in acid and in cleaning systems, but this paper examines inhibitive properties under conditions representative of oilfield corrosion.

Although few of the above substances are likely to be used alone as practical corrosion inhibitors, the information presented in this paper is useful to corrosion engineers dealing with oilfield corrosion. For example, further study might show tobacco extract to be a low cost component for corrosion inhibitor formulations.
An Improved Encapsulated Breaker to Decrease Hydrostatic Release and Increase Thermal Stability
Authors: Still John W. , McConnell S. Bruce , Miller Matthew J.
Published: December 2007

Encapsulating oxidizers with impermeable coatings is a well-known method for delaying the viscosity reduction of a fracturing fluid. It also enables the concentration of oxidizer breaker in fracturing fluid filter cakes formed during the leak-off and fracture closure process. The oxidizer is released by crushing the encapsulated particles during closure, but some oxidizer is also released before closure through a combination of hydrostatic release and mechanical abrasion.

This paper discusses the effect of the particle coating thickness on the hydrostatic release mechanism. Tests were conducted on encapsulated oxidizers with varying coating thickness to determine release rates at temperatures ranging from 175 to 250°F using a specialized oxidizer breaker release apparatus. The coating thickness required to minimize hydrostatic release was identified.

Analysis of both active and inactive oxidizer species during the hydrostatic release experiments also enabled the determination of the effective oxidizer breaker lifetime. Because oxidizers are designed to decompose into free radicals (the molecules responsible for polymer molecular weight degradation), shielding the oxidizer from the high-temperature environment extends the oxidizer breaker lifetime. We show that the encapsulation process is able to protect an otherwise unstable molecule from thermal and hydrolytic decomposition and the extent of the protection is related to the coating thickness.

The information obtained from this study was coupled with rheology experiments to validate breaker performance at temperature for a new thicker-coated oxidizer. The benefit of this material is increased concentration of active oxidizer breaker downhole, which facilitates fracture fluid cleanup and improves fracture conductivity and half-length.
Analytical Methods for Maintaining Quality Assurance of Recycled Fracturing Fluids
Authors: Hanes R. , Parker M. , Slabaugh B. , Weaver J. , Walters H. G.
Published: December 2007

Water-based hydraulic fracturing fluids typically use guar or derivatized guar to produce the properties required for proppant transport and fluid-loss control during fracturing operations. Guar is a high molecular weight polysaccharide that is water-soluble, generates good viscosity at low concentrations, and is economical. Low-viscosity base solutions are crosslinked easily with a variety of metal ions to generate highly elastic fluids that have excellent proppant suspension capability.

After a fracturing treatment is completed, this highly viscoelastic fluid must be degraded to a near water-thin liquid to facilitate fluid recovery. To accomplish this, the polysaccharide is extensively degraded through the use of a variety of chemical additives that were included in the fracturing fluid formulation. The resulting flowback fluid is not useful, and generally requires disposal.

A new hydraulic fracturing fluid, whose rheology is reversible and is controlled by pH, eliminates the need for polymer degradation. Because of this uniform viscosity reversal, the recovered frac fluid volume after well flowback approaches 100%. More importantly, since degrading agents are not required, the recovered fluid can be reused for subsequent fracturing treatments. This process results in reduced environmental demand by decreasing the volume of chemicals required for a fracturing campaign, the volume of water required, and reduced disposal cost.

To reuse recovered fracturing fluid, several nonconventional fluid analyses are required to ensure fluid stability and performance quality. This paper describes the onsite analytical procedures developed to analyze key chemical variables required for fluid reconstitution, making frac fluid reuse a reality.
Evaluation of CO2-Brine-Reservoir Rock Interaction with Laboratory Flow Tests and Reactive Transport Modeling
Authors: Wellman Tristan P. , Grigg Reid B. , McPherson Brian J. , Svec Robert K. , Lichtner Peter C.
Published: December 2007

Sequestration of carbon dioxide (CO2) in geological formations is one proposed method for isolating anthropogenic CO2 from the atmosphere. Determining the viability, risks, and optimal locations of sequestering CO2 in the subsurface requires detailed knowledge of the complex interactions among CO2, rock matrix, and pore fluids under appropriate in situ pressure and temperature conditions. Many physical and chemical processes are known to occur both during and after geologic CO2 injection, including diagenetic chemical reactions and associated permeability changes. Although it is commonly assumed that CO2 sequestered in this way will ultimately become mineralized, the rates of these changes, including CO2 hydration in brines, are known to be relatively slow. Together with hydrated CO2, cations from produced brines may form solid-state carbonate minerals, ostensibly providing permanent sequestration.

We used results of earlier laboratory CO2-brine flow experiments performed in rock core to calibrate a reactive transport simulator. We are using the calibrated model to estimate in situ effects of a range of possible sequestration options in depleted oil/gas reservoirs. The code applied in this study is a combination of the well known TOUGH2 simulator, for coupled groundwater/brine and heat flow, with the chemistry code TRANS for chemically reactive transport.

Variability in response among rock types suggests that CO2 injection will induce ranges of transient and spatially dependent changes in intrinsic rock permeability and porosity. Determining the effect of matrix changes on CO2 mobility is crucial in evaluating the efficacy and potential environmental implications of storing CO2 in the subsurface.
A New Approach to Inhibitor Squeeze Design
Authors: Kan A. T. , Fu G. , Al-Thubaiti M. , Xiao J. , Tomson M. B.
Published: December 2007

Oil field scale treatments can become more difficult when working with deeper non-conventional wells. Inhibitor squeeze is generally the most efficient scale treatment technology. However, inhibitor squeeze treatment is based more on experiences than mechanistic understanding of how the chemical interacts with formation rock and how it flows back. Better mechanistic understanding of the phosphonate/rock interaction is needed to derive innovative squeeze treatment for newer non-conventional wells. Significant progress has been made toward developing a quantitative understanding of the inhibitor/rock interaction, kinetics, stoichiometry, and equilibrium as inhibitors are injected into a formation and allowed to flow back. Four common oil field inhibitors (three phosphonates and one polyacrylate) are compared. In addition to calcite (CaCO3) in the reservoir rock, at least three phosphonate phases appear to be important, a low Ca and a high Ca amorphous Ca-P salts and a crystalline Ca-P salt, where "P" refers to a phosphonate molecule. The inhibitor/rock interaction follows four sequential reactions: (1) Limited acid attack of calcite; (2) Formation of a monomolecular coverage of phosphonate; (3) Reduction of further calcite dissolution due to surface poisoning by the Ca-P coating; (4) Precipitation of Ca-P solid with either low Ca or high Ca stoichiometry. Quantitative relationships between type of inhibitors, inhibitor concentration and acidity, kinetics of calcite dissolution and calcium-phosphonate precipitation are developed for the first time using a rule-based automatic approach. Consequences of the observations on squeeze design and scale inhibition will be discussed.
A Wettability Evaluation Method for both Gas-Liquid-Rock and Liquid-Liquid-Rock Systems
Authors: Li Kewen , Horne Roland N.
Published: December 2007

Methods that can be used to determine the wettability in both gas-liquid-rock and liquid-liquid-rock systems have been few. To this end, a method is proposed to evaluate the wettability in either gas-liquid-rock systems or liquid-liquid-rock systems. The method can be used to evaluate the wettability at a specific wetting phase saturation if the capillary pressure and relative permeability at this fluid saturation are known. The validity of the proposed technique was tested qualitatively and quantitatively using experimental data of capillary pressure and relative permeability from different systems. The wettability index calculated using the proposed technique was greater in the drainage case than that in the imbibition case, which is reasonable and consistent with the present understanding. The calculated wettability indices in gas-oil-rock systems were greater than in oil-water-rock systems as expected. Results also showed that the wettability index calculated using the proposed method may or may not be independent of fluid saturation in the cases studied.
Effective Control of Exotic Mineral Scales Under Harsh System Conditions
Authors: Yuan M. , Williamson D. A. , Smith J. K. , Lopez T. H.
Published: December 2007

In the Mobile Bay area of the Gulf of Mexico, occurrence of unique mineral scales in producing wells and flow lines has been a challenge to maintaining normal oil and gas production; and it has a high impact on operation cost. In addition to common scales (calcium carbonate and barium sulfate), the produced water often has a tendency of forming "exotic" scales, such as calcium fluoride, zinc sulfide and lead sulfide, which can cause plugging of subsea safety valves, and restrictions in the production flow lines, production headers and surface vessels. Furthermore, the problem has been compounded with the harsh system conditions (high temperatures, and high TDS and high calcium brines). This paper describes a successful scale inhibition program that has been developed from a careful analysis of the system and nature of the problem, a comprehensive laboratory product development and evaluation, and the implementation of the chemical treatment in the field.