bluuebunny/crossref_metadata_2025 huggingface dataset:
Integration of NMR with Other Openhole Logs for Improved Formation Evaluation
Authors: Minh Chanh Cao , Freedman Robert , Crary Steve , Cannon Darrel
Published: December 2007

The recently introduced measurement of total porosity from nuclear magnetic resonance (NMR) tools can help to identify the hydrocarbon type and to improve the determination of formation total porosity (t) and water saturation (Swt) in combination with other openhole logs. In shaly formations, porosities are difficult to estimate in the presence of hydrocarbons, especially for gas and light oils. Water saturations are even more difficult to estimate because critical parameters such as clay cation exchange capacities per unit pore volume (Qv), formation factors (F) and formation water resistivity (Rw) might not be known. The latter quantities are essential inputs into the Waxman-Smits and Dual-Water model saturation equations.

In the typical case of shaly gas bearing formations, both the total porosity corrected for the gas effect and the gas saturation (Sxgas) in the flushed zone can be derived by combining total NMR porosity (TCMR) and density porosity (DPHI). Adding resistivity logs such as Rxo and Rt helps to differentiate between gas and oil. Furthermore, the flushed zone water saturation (Sxot) computed from 1 - Sxgas can be used in many ways. One procedure uses Sxot in conjunction with the Rxo saturation equation to determine Qv or F. Another technique uses Sxot in conjunction with SP to estimate Qv when Rw is known. Yet, another method estimates Qv directly from the NMR short relaxation time part of the T2 distribution and use Sxot in conjunction with SP to estimate Rw. The new interpretation procedure follows the sequential shaly sands approach: first, determine porosity; second, determine shaliness and third, determine saturation. The new procedure improves on the classical method by offering new ways to compute Qv, F and Rw. The methodology is applied to a number of field examples.

P. 245
The Effects of Faulting on Production form a Shallow Marine Reservoir - A Study of the Relative Importance of Fault Parameters
Authors: England William A. , Townsend Chris
Published: December 2007

This paper describes a sensitivity study in which a variety of fault patterns was superimposed on a set of realistic heterogeneous sedimentary models of a near-shore marine environment. Using an experimental design technique, 32 faulted models were upscaled to a 40 acre (420m) water flood from which recoveries at water breakthrough and 1 MPVI were estimated by flow simulation. Statistical analysis of these data allowed us to study the relative effects of the various fault pattern parameters. We also studied the effects of adding faults to the same set of unfaulted reservoir descriptions.

In summary, fault plane seal was found to be the most important fault plane seal was found to be the most important fault parameter influencing recovery at water breakthrough. Recovery at 1 MPVI was influenced by cross fault presence and fault plane seal. The stacastic noise in the modeled recoveries was increased significantly when faults were added. The influence of the sedimentary parameters was not eliminated by the addition of faults, although some significant reductions did occur for recoveries at 1 MPVI.

An important effect appears to be the reduction in sweep efficiency when injector wells are placed near to sealing faults. Conversely, in layered (hydraulically sealed) sedimentary models, faulting can increase recovery by improving cross communication.

P. 279
Inflow Performance Relationships of Horizontal and Multibranched Wells in a Solution- Gas-Drive Reservoir
Authors: Retnanto Albertus , Economides Michael J.
Published: December 2007

In predicting and optimizing the performance of single and multiple wells, or complex well architecture, within a drainage or flow unit, we have favored benchmark analytical or semianalytical models. Recently. a general productivity model has been constructed and presented that allows for the performance prediction of any single- and multi-well configuration within any reservoir geometry in both isotropic and anisotropic media. Such an approximation is known to have limitations when applied to two-phase reservoir flow. This work used a numerical simulator to generate IPR's for horizontal or multibranched wells producing from a solution- gas-drive reservoir. First, a base case is considered with typical fluid, rock, and reservoir properties. Then, variations from the base case are investigated. These variations cover a wide range of fluid, reservoir, and well characteristics. The effects of numerous reservoir and fluid properties on the calculated curves are investigated. Bubblepoint pressure and reservoir depletion have a significant effect on the curves. A generalized dimensionless IPR based on nonlinear regression analysis of simulator results is developed. This IPR curve is then used to predict the performance of horizontal and multibranched wells in a solution-gas-drive reservoir combined with our productivity model. For relatively low bubblepoint pressures, the curves coalesce on Vogel's classic relationship. For higher pressures they deviate substantially.

P. 239
Application of Interpolation In-Field Referencing to Remote Offshore Locations
Authors: Williamson H.S. , Gurden P.A. , Kerridge D.J. , Shiells G.
Published: December 2007

A method for modelling the crustal magnetic field vector from total intensity data has been used to determine the magnetic field snapshot required for Interpolation In-Field Referencing (IIFR). The method has been validated in a number of ways, including comparison of magnetic and gyroscopic survey data in three UK fields.

P. 387
Case History of the Implementation of a Fast Track Gas Production SCADA Project
Authors: McLean Dan , Alvis Vern
Published: December 2007

Field Automation systems comprising EFM and SCADA Technology continue to improve the profitability of oil and gas producers through increased visibility of remote wells and improved accuracy and delivery of production data. The installation of SCADA forms the backbone for other departments within the enterprise to enable pro-active business decisions. The direct benefits of SCADA can be realized as soon as the systems are in service. To achieve the benefits as soon as possible a fast track approach to the retrofitting of wells and compressor plants was taken. The case history presented will describe the SCADA system and installation plan, and indicate the benefits realized from a business management perspective.

The implementation of the SCADA system for PanCanadian Petroleum Ltd. was termed the Gas Production Inquiry Reporting System (GPIRS) and comprised automation of approximately 500 wells and 35 compressor stations/gas plants throughout southern, central, and north-western Alberta. The 1993 budget of $25M CDN for the retrofit work was staged in two parts with Phase I measurement implementation completed in 8–9 months, the Phase II automation implementation completed over 9–10 months the following year. The main topic of this case study is the nature of the implementation, including interfacing and coordination of many disciplines in order to achieve a fully installed and commissioned system. Numerous contractors, sub-contractors and PanCanadian internal groups participated in the project. It will be shown that the resultant improvements in gas deliverability and improved marketing substantially justified the capital cost.

P. 291
Identifying and Meeting the Key Needs for Reservoir Fluid Properties A Multi-Disciplinary Approach
Authors: Moffatt B.J. , Williams J.M.
Published: December 2007

With emphasis on fast-track developments often involving small fields or harsh conditions, reliable reservoir fluid properties are becoming increasingly important. However pressure on staffing levels can lead to inadequate expertise within operating companies for identifying needs, for justifying sampling analysis costs, and for validating results.

The work involved an investigation of physical and chemical fluid property requirements within the entire Exploration and Production organization of an operator. The information obtained was used to rank key properties and was compiled in a suitable format to assist less-experienced staff in identifying areas of primary concern. Field sampling and laboratory analytical practices were also investigated, and a series of Best Practices developed. An additional investigation was performed to quantify typical financial risks on the basis of experience. It is demonstrated that even relatively poor- accuracy measurements, if made at an early stage of a development, can have very significant information value. Once fully implemented, this work should have a major effect on reducing the risks of unexpected production problems, of improper facilities design and of out-of-specification sales product.

The paper reports the key fluid characteristics identified by a wide range of disciplines, and the risks associated with inadequate fluid property data are quantified in terms of the dollar cost of failures or missed opportunities. Best Practices for sampling and analysis of well test fluids are made available.

The methods presented can be used widely by petroleum industry professionals to identify and satisfy needs for reservoir fluid properties.

P. 315
Practical Analysis of Drilling Mud Flow in Pipes and Annuli
Authors: Zamora Mario , Lord David L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

New numerical and graphical techniques permit practical assessment of drilling mud hydraulics. Developed from a sound theoretical analysis of power law fluids, they are extended by power law fluids, they are extended by a generalized model to approximate Bingham plastic and power law with yield stress behavior. Applicable equations are expressed in terms familiar to the field engineer.

A proposed geometry factor reduces the hydraulic equations to a single set describing pipe, parallel plate and annular flow. It also defines a generalized Reynolds number for different geometries and flow regimes found in the circulating system.

Introduction

Drilling muds are non-Newtonian fluids. As such, the equations describing their rheological behavior are both complex and bulky. This is true even under assumptions of isothermal, steady-state flow in circular pipes or stationary concentric annuli.

There is a gap between theoretical work in mud hydraulics and its application in the field. This is unfortunate because theory and laboratory data must eventually be correlated to actual behavior in the well. Major efforts to eliminate this gap include extensive simplification of the rheological equations and use of wellsite computers. Approximations for field use are necessary; however, oversimplification can lead to errors. Most wellsite mini-computers (or programmable calculators) have limited core, making it difficult, if not impossible, to do justice to present rigorous solutions.

This paper presents a practical approach to calculate surge/swab and other wellbore pressure losses. pressure losses.
A Novel Approach to the Exploitation of Deepwater Gas Fields - The FPLSO Difference
Authors: Stephens K.R. , Ronalds B.F. , Piermattei E.J.
Published: December 2007

The introduction of regulations prohibiting the flaring of natural gas, the increase in demand for a clean burning fuel, the improvements in liquefaction and offloading technologies, and the potential for mobility of a floating natural gas processing, liquefaction, storage and offloading vessel which could exploit several smaller reserves over its effective operating life, will permit the development of smaller fields located in deeper water, further offshore and lacking in existing infrastructure; fields once considered marginal. The FPLSO vessel is the key for the exploitation of these fields. The focus of this paper is the motions response of the Floating semi-submersible natural gas Processing, Liquefaction, Storage and Offloading (FPLSO) vessel when subject to wave loading from the head seas direction in Australian North West Shelf Conditions. This is of particular interest due to the fact that the length of the vessel is unprecedented, 478 metres.

P. 131
Reservoir Evaluation Through Extended Well Testing-Moran Field, PNG
Authors: Wali K.F. , Bantz D.M. , Pedersen K.N. , Karaman O.S.
Published: December 2007

An extended well test (EWT) is currently being conducted in Papua New Guinea(PNG) in the recently discovered Moran Field. The objective of this EWT is to evaluate reservoir volume, deliverability, recoverable oil and communication within major fault blocks. This information is being integrated with other reservoir data acquired during field delineation for optimising full-field development of this geologically complex field.

Introduction

The Moran field, located in the Southern Highlands Province of Papua New Guinea, was discovered in September, 1996, in the same production license (PDL2) as the presently producing Kutubu fields. Oil was found in the same two separate intervals, the Toro and Digimu sands, that presently produce at Kutubu. Initial well test rates were over 8,000 barrels per day of high-gravity, sweet oil from each interval. A follow-up delineation well discovered an additional reservoir and extended the oil column height over 4000feet in two major fault blocks.
Design Optimisation of Laminaria/Corallina Fields Subsea Facilities
Authors: Smith N.T.G. , Hamp R. , Maloney M.
Published: December 2007

Woodside Offshore Petroleum, together with joint venture participants Shell Development Australia and BHP Petroleum, are developing the Laminaria and Corallina Fields in the Timor Sea. The selected development concept is a floating monohull production facility supplied by subsea wells. This paper describes the approach taken by the Project team to deliver a diverless deepwater subsea facility which met the objectives of flexibility and maximised value whilst accommodating the evolving subsurface modelling process. A key element of the approach selected was the philosophy of Best Managed Risk (BMR), and the application of this philosophy to deal with reservoir uncertainties during the subsea design process is discussed. A second key element was the early definition of a "minimum facilities field layout" to which additional facilities could only be added if justified by a rigorous business case which demonstrated added value to the Project. The benefits of this strategy in allowing capital expenditure to be controlled in the face of significant uncertainties is discussed and supported by several examples.

P. 327
A Strategic Approach to Designing FPSO Vessel Power Generation Systems
Authors: Colton Jonathan S. , Low Yee Weng
Published: December 2007

A design process is proposed as a strategic approach for designing FPSO vessels power generation systems. The design process is formulated based on analyses of both offshore- based and land-based power generation system design issues, and with the belief that the design process is both effective and efficient if it treats as many of the relevant economic and project engineering issues as possible. A design process framework and a power generation systems design problem are described and discussed.

P. 339
Fast Connector for Drill-Pipes
Authors: Kamp G.P. , Bakker T.W. , Smith J.E. , Young T.F.
Published: December 2007

With the increasing focus on creating possibilities to economically develop marginal fields, the basic rotary drilling concepts are being reviewed to reduce the costs of drilling wells. This paper presents a preliminary design of a Fast Connector, which reduces the make-up time, while the mechanical performance is comparable to that of conventional tool-joints. The geometry of this specific connection provides even some extra features, which are not possible with conventional tool-joints.

P. 351
Laboratory Testing and Field Implementation of Scale Inhibitor Squeeze Treatments to Subsea and Platform Horizontal Wells, North Sea Basin
Authors: Jordan M. M. , Tomlinson C. J. , Pritchard A. R. P. , Lewis M.
Published: December 2007

This paper presents field results from a number of scale squeeze treatments carried out on subsea and platform horizontal wells from a field in the North Sea (Nelson field). The evaluation of scale inhibitor chemicals from initial laboratory screening is reviewed along with significant factors which influence inhibitor selection when designing squeeze treatments for both horizontal and highly deviated wells. This includes discussion of formation brine/inhibitor incompatibility and formation minerals/inhibitor incompatibility. The potential for sand production and oil-in-water process upset which can result from the above factors is also discussed.

This paper outlines the practical difficulties in squeezing subsea horizontal wells and how some of these problems can be overcome. Some of the practical solutions discussed include the use of chemical stabiliser to reduce formation brine/inhibitor incompatibility, variation of pump rates to encourage propagation of inhibitor along the wellbore and the potential of fluid diversion (both mechanical and chemical). The significance of production logging data or good reservoir simulation data, to evaluate the location of water production prior to a squeeze treatment, is also stressed. This paper also presents details of divertor selection and the resulting squeeze design strategies that may be implemented.

From this series of field squeeze treatments it can be concluded that the wells have all been successfully treated, with minimal process upset during flowback, as a result of continuous design improvement based on the previous treatments. No long term decline in well productivity was observed as a result of these treatments. This paper clearly shows that with the correct laboratory evaluation process for both scale inhibitor and divertor agents and with utilisation of production logging and reservoir simulation data, it is possible to squeeze scale inhibitors into platform and subsea horizontal wells without the need for coiled tubing intervention.
Results of a Field Test to Improve Hydraulic Blowout Control Calculations
Authors: Oudeman P. , Mason D.
Published: December 2007

In the offshore environment, options to regain control over a blownout oil or gas well directly from surface, e.g. by capping are limited, particularly in the case of subsea wells or underground blowouts. Hence injection of a kill fluid via a relief well will often be the only alternative. In view of offshore logistics and cost of such an operation, this requires reliable estimates for the kill rate, pump pressure, hydraulic horsepower, kill fluid density and volume, prior to spudding relief well(s) and arranging for the pump equipment, fluid make-up plants and storage capacity. Various methods to estimate these parameters have been proposed. Validation of the methods has been very limited however since an actual blowout situation, with all inherent uncertainties (e.g. with respect to blowout well performance) does usually not allow a thorough kill job evaluation. To close this gap between theory and practise, a dedicated full scale field test to study how a dynamic well kill proceeds in a high rate gas well, has been designed, executed and analysed. Through variation of the blowout and kill rates, conditions under which the well ceased flowing could be determined accurately. Valuable insights on the processes taking place in the well during the kill were obtained. Analysis of the test results shows the correct methodology to predict the parameters for a successful and efficient kill job.

P. 103
Multiple Proppant Fracturing of Horizontal Wellbores in a Chalk Formation: Evolving the Process in the Valhall Field
Authors: Norris M.R. , Berntsen B.A. , Skartveit L. , Teesdale C.
Published: December 2007

Oil production from this chalk field has been improved significantly over the last three years through the use of multiple proppant fractures placed from horizontal completions. Following early successes the engineering effort now focuses on increasing value through engineering innovation and increased productivity. This paper describes, through case histories and field data, the advances made in the design and execution of these completions over the first 13 such wells in the field.

Wellbore completion activities and stimulation are now performed as a standalone process through the use of specialized large diameter coil tubing equipment so allowing on-going drilling operations to be performed concurrently. This has significantly reduced daily spread costs while bringing wells on production within a much reduced time frame. This lower cost environment has also allowed innovative field procedures to be developed resulting in further improvements such as proppant plugs for isolation between stimulation zones and treatments using recycled proppant to minimize waste.

Treatment design has been refined through downhole pressure monitoring which has allowed empirical frictional relationships to be developed for proppant slurry and coil tubing circulating fluids. This data validates the wellbore tubulars design and allows any weak points in the arrangement to be highlighted for change. An extensive fracturing database is maintained allowing each treatment design to be compared with previous experience in the field.

Productivity is the driver for economic success and treatment design requirements have evolved through laboratory testing to account for longer term downhole operating conditions below the bubble point while also improving initial conductivity. Field data to date through PLT logging has confirmed the hydrocarbon contribution from each fracture and this is used to validate, or otherwise, the effectiveness of each treatment. Normalized well productivities continue to improve and the challenge is to maintain the rate of evolution through the improved application of both new and existing technologies.

P. 335
Emulsified Acid Enhances Well Production in High-Temperature Carbonate Formations
Authors: Navarrete R.C. , Holms B.A. , McConnell S.B. , Linton D.E.
Published: December 2007

Emulsified acids were traditionally used in acid fracturing, and more recently on matrix treatments of carbonate formations. The delayed nature of emulsified acids is useful in generating longer etched fractures or deeper wormholes. Emulsified acids also have higher viscosities than straight acid, which reduces fluid loss in acid fracturing applications and helps distribute acid more uniformly in formations with high-permeability contrast during matrix treatments. A new emulsified acid system is presented in this paper that is stable up to 350 F, highly retarded, and significantly more viscous than straight acid. Laboratory data comparing emulsified acid with straight acid are presented at temperatures ranging up to 350 F, including rheology and acid conductivity. Field case histories in the Smackover formation in Alabama over two years are presented. The field case histories show the improvements in production of oil and gas resulting from emulsified acid fracturing treatments in comparison with prior similar treatments done with straight acid.

P. 391
New Technology, Invert Emulsion Scale Inhibitor Squeeze Design
Authors: Lawless T. A. , Smith R. N.
Published: December 2007

Normal squeeze injection strategies employ inhibitor based formulations and brine overflushes to penetrate radial distances of ~12 feet. However, as a direct result of this strategy, oil continuity between pore spaces in the near well bore area is lost, leaving discontinuous oil droplets resident in the pore spaces. Relative permeability effects dictate that following shut-in, water production will be favoured, whilst oil will have to overcome physical barriers before oil continuity, between pore spaces, to the well bore location can be achieved. As such, the major costs associated with squeeze exercises are those incurred as a direct result of deferred oil production, arising from failure to return to pre-squeeze oil productivity for periods between 3 and 21 days.

The ability to utilise invert emulsion technology (brine dispersed in kerosene) with the aqueous phase containing a scale inhibitor in solution is presented as an attractive alternative. The proposed technology will combat current deficiencies and deliver a new approach to the process of scale control. It is important for squeeze operations, however, that the emulsion can be injected safely downhole and encouraged to "break" during shut-in, thus allowing the aqueous inhibitor to be released and contact the rock structure, promoting effective retention. The "broken" oil phase maintains continuity between pore spaces and promotes rapid oil productivity to return, post-squeeze, as a result of relative permeability effects. Economic benefits are identified and detailed considerations relating to the appropriate physicochemical and environmental characteristics of target emulsions are presented. Experimental and theoretical evaluation exercises on promising emulsion formulations for field applications are presented and reviewed.

Emulsion compositional requirements for successful field applications have been systematically addressed using phase mapping routines to establish preferred candidate selection. The method of emulsion manufacture, its phase volume composition, destabilisation route and resulting rheological characteristics are described along with the development of a model to describe fluid viscosity over a range of likely field conditions. Compatibility with selected field stock tank oils and formation waters are reported over a range of mixing ratios to establish application potential. Coreflood routines, conducted at 90°C, using a conventional squeeze approach as well as a formulated, controlled breakage, invert emulsion system are presented. Both squeeze treatments reveal equivalent inhibitor return characteristics, but post-squeeze oil production for the emulsion system shows inherent benefits.
Drill-In Fluid Filter-Cake Behavior During the Gravel-Packing of Horizontal Intervals — A Laboratory Simulation
Authors: Becker Thomas E. , Gardiner Nicholas H.
Published: December 2007

A simulated horizontal well section allows studies regarding the buildup and removal of drilling-fluid filter cake. For the study described in this paper, researchers used the well section to examine the effects and behavior of drill-in fluids before, during, and after gravel packing. Specifically, the following conditions were examined: (1) filter-cake thickness, (2) filter-cake permeability, (3) local permeability variations behind the sand face, and (4) the effects of sand scouring on the preceeding three quantities during gravel packing.

The 6-ft long test apparatus resembles a linear section of casing-and-borehole annular space where differential pressure can cause drilling-fluid filter cake to develop. Temperatures in the apparatus can be increased, as needed, up to approximately 200°F, and fluid is flowed axially through the rectangular flow channel. The special design of one channel wall, which consists of permeable, unconsolidated sand, supported by screen, allows filter cake to build up. The fluid is flowed through the channel until the cake-building pressure is balanced by the flow's erosive forces.

The drill-in fluid temporarily plugs the sandstone face, allowing the axial flow to carry the gravel-packing sand throughout the length of the horizontal section. Laboratory tests with this apparatus showed that a properly selected drill-in fluid can plug a high-permeability sand within seconds after contact, and reduce permeability a 1,000-fold. This low permeability can be maintained throughout the sand-pumping process, even when the filter cake is almost completely eroded.

To date, this plugging procedure has been used successfully on multiple horizontal wells with a typical horizontal-section length of 1,000 to 2,500 ft, and plans are underway for it to be used on more wells. Laboratory test results closely agree with the results observed in these field wells.
A Stimulation Treatment of a Sub Sea Well Using a Scale Dissolver
Authors: Børeng Raymond , Bakken Knut Olav , Vikane Olav , Angelsen Atle
Published: December 2007

The Stattjord East and North are two sub sea fields tied in to the Stattjord C platform on the Stattjord Field. A well, on the Stattjord East satellite was damaged during the gravel pack operation. The damage is believed to be rust particles due to use of dirty drill collars during placement of the pre pack gravel. The productivity index, PI, of the well after clean up of the perforations, i.e. prior to gravel packing, was calculated as 742 Sm3/d/bar. After gravel packing and bean up of the well, the PI was calculated as 55 Sm3/d/bar. The well observed increased productivity to about 80 Sm3/d/bar before its decline prompted the use of a scale dissolver to remove the damage. The challenge was to pump the scale dissolver 7.8 km from the platform out to the wellhead template through a 2.5 inch methanol line. At the time of performing the stimulation treatment the oil rate of the well was 776 Sm3/d with a PI of 11 Sm3/d/bar. The maximum pumping rate during the operation was 800 litres per minute. After the scale dissolver had been soaked in the gravel pack for 12 hours, the well was put on production and it delivered 2600 Sm3/d of oil. The PI was increased to 55 Sm3/d/bar. A decline in production was observed, and after a year a second squeeze was performed successfully. The PI increased this time from 23 to 59 Sm3/d/bar and the oil production increased with 1000 Sm3/d. For the first time in the Norwegian North Sea, successful stimulation treatments of a sub sea satellite well has been achieved by pumping a scale dissolver through a 2.5″ methanol line into a 5.5″ completed well.

The evaluation of the data has shown that the plugging process is complex and difficult to interpret. However, it can be concluded that injection of fluids has improved the gravel pack productivity. The erosion potential has also been minimised due to reduced draw down across the gravel pack.

The damage mechanism is most likely a combination of rust, brine and fines plugging the wire wrapped screens and the poorly filled perforation tunnels.

The first stimulation operation had a payback time of 2 days and the second operation 4 days.
Rapid Risk Ranking for Field Development Optimisation to Achieve ALARP
Authors: Burch M. E. , Goddard J.
Published: December 2007

The recent changes in Safety Legislation and Guidelines away from prescriptive requirements are becoming increasingly well known and understood. However, the tools and processes for managing risk are not keeping pace with these changes. With this broader scope to optimise risk, the top performing companies and their managers demand answers to ever more challenging questions, testing the capabilities of safety and risk professionals. This is never more so than during the engineering phase of new projects where timely, correct decisions are essential – particularly when personnel safety, asset protection and project economics (cost, revenue and schedule) are some of the main decision criteria.

One of the goals of effective risk management is to ensure that risks have been reduced to as low as reasonably practicable (ALARP). Managing risks at the earliest stage of a project to ALARP will result in achieving an inherently safe development with an associated maximisation of Net Present Value (NPV).

In order to meet these objectives, risk and safety professionals need tools to support engineering. These tools must perform quantitative cost benefit trade-offs efficiently and effectively.

This paper explains the nature of these challenges and decisions, together with a methodology and tools which manage risk (while maximising NPV) and assist in the decision making process.
Wireline Tractor Production Logging Experience in Australian Horizontal Wells
Authors: Local Eddiexz , Searight Thomas L.
Published: December 2007

New wireline tractor technology has been developed and used successfully in Australia to deploy production logging tools in horizontal wells. The results of operations in the Wandoo field in Australia are presented. The dynamics of tractor operations have been modelled, and field data has been used to validate the model and to quantify borehole friction coefficients. The model may be used to assist job planning and to assess the feasibility of deployment by wireline tractors in general situations.
Practical Solutions to Combat the Detrimental Effects of Hydrogen Sulfide During Drilling Operations
Authors: Carney Leroy L. , Jones Bob
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper includes a history of the efforts which have been put forth to minimize or eliminate the various problems caused by hydrogen sulfide.

When hydrogen sulfide enters the borehole during drilling, completion, or testing for hydrocarbons, it creates several very detrimental problems. These problems are encountered regardless of the source of the hydrogen sulfide.

Hydrogen sulfide can be dangerous to personnel on the surface, can cause cracking personnel on the surface, can cause cracking of drill pipe and tubular goods, and destruction of testing tools and wire lines.

Less severe problems, however still important to good drilling practices, are incompatibility of hydrogen sulfide and drilling fluids and obscurement of test results for other ions contained in drilling fluids filtrates which are important to successful drilling practices.

The advantages and disadvantages of using the following compounds for scavenging hydrogen sulfide from water base drilling fluids are compared.Copper CompoundsZinc CompoundsIron CompoundsHydrogen PeroxideChelates

The use of oil base drilling fluids instead of water base fluids for drilling has certain advantages in areas where hydrogen sulfide is likely to be encountered.

Designing special invert emulsion base fluids for use in completion and drill stem testing is suggested and the chemistry of these specially designed fluids is explained.

Testing for the presence of hydrogen sulfide in drilling fluids is discussed.

Many of the efforts that have been reported by service companies and oil companies for combating hydrogen sulfide during drilling operations are summarized.
A Review of the Theory and Practice of Two-Phase Flow in Gas-Liquid Transmission Systems
Authors: Brookbank M.R. , Fagiano P.M.J.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The development of frictional pressure drop correlations for two phase flow is reviewed covering the contributions of Lockhart and Martinelli, Baker and Duckler. A new equation is presented for prediction of the multiplying factor () for frictional pressure drop in two phase flow which gives pressure drop in two phase flow which gives results very similar to those predicted by Duckler's case 2 method.

1.82 V (1-Rl) 1 x2= {1 + l} x +g --- ------- ----- ----Vg Rl (1-Rl)2.4 Rl 1.8

The effect of vertical rises and undulations on the overall pipeline pressure drop is discussed. A hypothesis is presented for the mechanism of massive liquid and gas surges which have sometimes been observed at reception terminals for two phase pipelines. pipelines

Introduction

Although there are now many two-phase gas-liquid transmission pipelines in use, some of which have been in operation for many years, and although a number of research projects have been initiated on the subject projects have been initiated on the subject over the last three decades, there still remains much to be learned about the various phenomena occurring in two phase flow. The phenomena occurring in two phase flow. The present paper reviews some of the criteria present paper reviews some of the criteria which are used in designing two phase transmission systems and contributes some new thoughts on the subject.

THE DEVELOPMENT OF TWO-PHASE FRICTIONAL PRESSURE DROP CORRELATIONS PRESSURE DROP CORRELATIONS

For many years since its development in. the late 1940's the Lockhart - Martinelli correlation represented the most accurate and most widely used method for the calculation of frictional pressure drop in two phase flow. This correlation was based on experiments using air and various liquids in pipes of 1" diameter and less. It expresses a multiplying factor (2) as a function of the ratio of the pressure drops for the liquid phase flowing on its own and the gas phase flowing on its own (X2). The product of this multiplying factor and the product of this multiplying factor and the pressure drop for one of the phases flowing pressure drop for one of the phases flowing on its own is then the friction pressure drop for two phase flow.

Lockhart and Martinelli identified four types of flow which depend on whether the flow is viscous or turbulent for each of the phases. phases.
Cuttings Flux Measurement and Analysis for Extended-Reach Wells
Authors: Thonhauser Gerhard , Millheim Keith K. , Martins Andre L.
Published: December 2007

Cuttings transport efficiency is one the most critical issues, to be considered, for drilling a successful extended reach well. Recent efforts to develop transient models to simulate cuttings flux in extended reach wells let to the conclusion to develop a tool to measure cuttings flux over the shale shakers to determine hole cleaning performance. Standard rig procedures did not prove to be sufficient to monitor the cuttings transport efficiency and provide data as basis for such a simulation.

A mechanical device was built to measure the amount of cuttings "produced" from the wellbore. The combination of this information with the real time data acquisition of other drilling parameters was used to analyse the hole cleaning behaviour of the wellbore.

Hardware was built to fit multiple situations on- and offshore to be as flexible as possible. The major part of the development was to provide the means to interpret the collected data and retrieve valuable information to evaluate hole cleaning performance of the system. The measurement system was designed to satisfy two different objectives for data collection.

First to provide the basis for real-time interpretation to optimise circulating strategy, and schedule, based on the information retrieved. The quantitative measurement of the cuttings flux allows to compare generated versus "produced" cuttings. The comparison enables the driller to determine when to circulate to clean the annulus, thus avoiding unnecessary circulating time – meaning cost. Furthermore it was tried to correlate measured cuttings flux with wellbore stability problems, as well as overall drilling performance.

Second to provide the basis for drilling data post analysis. This includes representative data sets for a sequence of wells, accessible for the drilling engineer to optimise well planning. Such a data set could also be used to feed a learning hole cleaning simulation.
Slimwells Without the Pain
Authors: Head P. , Turner D. , Hanson T. , Al Rawahi S. , Cameron G.
Published: December 2007

Slimming down the well geometry to reduce the cost of well construction has been an economic goal of operators for many years 1,2,3,4. Historically, this has resulted in small diameter holes across the reservoir with the associated problems of specialised equipment requirements, reduced drilling rates, complicated well evaluation and reduced flow path. In addition, systems to date have also introduced severe operational drawbacks such as high surge and swabbing pressures during casing installation and high circulation pressures while cementing.

This paper will present the results from a joint industry project (JIP) the object of which was to address these issues, and provide an effective solution to overcome these drawbacks. The common approach throughout all of the well construction processes described in this paper is a series of liners, with tiebacks to previous liner tops as required. Finally the well is completed with a monobore tieback to surface.

The main technical challenges to overcome were:

- How to terminate each liner hanger with so little annular space while still retaining the same tensile load capacity as the virgin pipe. This was achieved by engineering a unique liner hanger system which requires no moving components, and which forms a metal to metal seal with the previous liner.

- To prevent the open hole being exposed to excessive pressures during liner installation, and while cementing. This was resolved by a novel conveyance system which allows for two modes of fluid circulation while the liner is being deployed and landed in the well, with a third conventional mode for circulating and cementing operations.

With the current trend towards deepwater operations smaller riser and casing configurations offer significant advantage over conventional well architecture. Figure 1 shows two potential casing configurations using this technology. The first illustrates the application of a taut leg moored 4th generation rig employing a 16" riser (the limit of its capability in great water depths). The second and slightly more radical application of this technology illustrates an 8" reeled riser from a DSV deploying the coiled casing option. Both these examples illustrate how this innovative project has broadened the range of options for well architects/engineers.
Rig Floor Accidents: Who, When and Why? - An Analysis of UK Offshore Accident Data.
Authors: Dobson J. D.
Published: December 2007

Rig floor accidents and dangerous occurrences account for almost 30 % of all reported accidents offshore on the UK Continental Shelf. They include fatalities and serious injuries. It is an imperative of both industry and regulators that the frequency of these accidents is reduced significantly.

Analysis of accident data held by HSE, the UK regulator, has identified the most frequent types of accident, the most common injuries, when accidents are most likely to occur and who is most likely to be injured. Analysis of the data has also been carried out to determine the impact of rig mechanisation on accident frequency. While many of the findings are as one would expect, there are also some surprising features. The analysis reveals that accidents are most frequent at the beginning of shifts and when shift pattems change. Personnel most at risk are floormen and roustabouts, especially those new to the industry and those with around 7 years’ experience; they occur most frequently in the age range 26 to 30. Most common injuries are those to hands. Mechanisation of rig floors makes a small but significant improvement to rig floor safety, mosl notably by the installation of top drives.

Earlier project work by HSE looked at the steps the industry was taking to reduce injury from dropped objects in drilling derricks and from manual handling accidents. Current projects sponsored by HSE include develop:nent of guidance to help assess rig floor design and layout to minimise human factors in the cause of accidents.
Virtual Experience Simulation for Drilling - The Concept
Authors: Millheim Keith K. , Gaebler Thomas
Published: December 2007

Future management of drilling operations will face new hurdles to reduce overall costs, increase performance; and to do this with possibly less retained experience and organizational drilling capacity.

Over the past fifteen years huge drilling data accumulations evolved as part of the drilling process. Although unused these inert data accumulations offer the new possibility to create what will be called a Virtual Experience Simulation (VES) for drilling.

This paper presents a new concept based on heuristics. Unused data accumulations are processed (or activated) using a technique cited in the paper. An example, using a 22 well data accumulation is processed into specific data sets for geology, tripping, cementing, logging, penetration rate, and unscheduled events. These new data sets now have a value added by retaining the field drilling experience and knowledge.

The last part of the paper explains one type of heuristic computer simulation engine (using system dynamics) that gives the user access to this virtual drilling experience and knowledge.

It is believed the work in this paper offers evidence that the VES is a new way to retain field drilling experience in a way it can be learned by others as virtual experience.
Dynamic Behaviour of a Bit-Motor-Thruster Assembly
Authors: Schmalhorst Bernd
Published: December 2007

Case studies show that the use of a thruster in the bottomhole assembly of a drillstring is beneficial for the operator because of a considerably improved rate of penetration and smooth drilling conditions. From a dynamics standpoint, the axial and torsional vibrations of the drillstring are improved by the use of a simple thruster device. The thruster acts like an ‘anti-vibration’ tool. Laboratory measurements of a full scale assembly containing a bit, a downhole mud motor and a thruster were carried out to quantify the forces, accelerations and dynamic pressures. Measurements were made at a 6kHz sampling rate and under various operating conditions. The signals were analysed by digital signal processing techniques to determine dynamic characteristics. The dynamics of the considered systems were then described by transfer functions. In these tests, the measured vibration response was used to calibrate the unknown parameters of a bit-motor-thruster dynamics time domain model that includes mud flow forcing effects. The computer application then predicts the dynamic behaviour of a complete drillstring while drilling.
Well Engineering Aspects of a 2 7/8in Ultraslim Lined Well Campaign
Authors: Saville P. , Hoorn F. Van , Edbury D.
Published: December 2007

This paper presents the well engineering aspects of a 2 7/8in Ultraslim lined Well Campaign. The application of this technology is seen as an essential capability for development of some mature fields. The 2 7/8in wells are sidetracked from existing 4 ½in horizontal liners. After milling a window in the horizontal liner, a 3 3/4in hole is drilled utilizing logging while drilling tools. The 2 7/8in liner is run, cemented, perforated and acidised. Operations are conducted through the existing 4 ½in Gas Lift completions or 4 ½in parasitic strings.
Lessons Learned During Deepwater Drilling Operations West of Shetland
Authors: Lesiuk Joseph , Rennie Andrew , MacPhail Ian , Cummins Ian
Published: December 2007

The frontiers of drilling in harsh environments are continually being pushed back. Since 1994, drilling rigs have successfully operated at all times of the year in the deep waters of the Northeast Atlantic Margin. Lessons learned from experience in these hostile waters are guiding rig development.

The Sovereign Explorer, a GVA 4000 design, was the first rig to operate around the year in the area and in water depths greater than 1500 ft during 1994 and 1995. As a result of this experience, extensive rig riser modifications were made to facilitate operation in the stronger-than-expected currents before a second round of drilling. A riser recoil system was installed to allow a controlled retraction of the slip joint during disconnection of the lower marine riser package (LMRP), and additional riser tensioners were fitted to reduce tensioning system operating stress levels.

Further modifications are planned, including active heave compensation and an improved BOP control system. Heave compensation will allow the Lower Marine Riser Package (LMRP) to be re-latched in 8- to 12-ft heave conditions rather than 4- to 6-ft heave, with an estimated saving of seven rig days per year. Improved BOP control, together with other modifications, will extend the rig's water depth limit to 4500 ft.

The challenges set by the difficult operating conditions encountered in the Northeast Atlantic Margin are discussed, together with some of the solutions already tested and other developments proposed.