bluuebunny/crossref_metadata_2025 huggingface dataset:
Hazardous Waste Disposal Using Co-Processing
Authors: Rustamina A. , Oepoyo P. , Aloysius V. , Sadono I.
Published: December 2009

Schlumberger Indonesia provides wide range of services in oil and gas industry. From Schlumberger activities in local facilities generate amount of wastes that are categorized hazardous wastes. Schlumberger Indonesia has commitment to improving the hazardous waste disposal using environmental friendly disposal method.

The common hazardous waste disposal method in Indonesia is incineration, stabilization and secures landfill. This method is not integrated, generates new category of waste (example: toxic gas, ash residue and leach ate), new environmental impact1 and require high operational cost.

Based on author cognition, only exiguous integrated hazardous waste Disposal Company obtain operation license from the MOE and provide service covering the waste transportation, collection, application, processing and pilling3.

This paper describes how Schlumberger Indonesia efforts to explore and examine processes in other industries, which can utilize to improve hazardous waste disposal. From several available alternatives and after careful considerations, then decided high temperature in cement kiln is the best disposal method.
Bio-Genetic Engineering, Future of Multi Microbial Culture EOR— A Detailed Report
Authors: Kurawle Irfan , Kaul Mohit , Mahalle Nakul , Nair Amith , Kulkarni Nikhil , Amin Zohaib , Carvalho Vickey
Published: December 2009

Microbial Enhanced Oil Recovery has been known to the industry for decades and yet the research has only been applied to a selected few pilots where analysis of the in situ Microbes was made. The advent of Bio-Genetic Mapping of Microbes has introduced us to various strains of bacteria that can be genetically altered to produce alkali and surfactant needed in chemical floods in much higher concentration than previously thought. We conducted some initial experiments from which the enhancement of recovery factor is significant. The results and data generated were then used in STARS™ a compositional reservoir simulator to model the effect of various by-products (Polymer, Surfactants) generated by microbes on the recovery process. The surfactants generated lead to reduction of Interfacial tension from 30 to 0.1 dynes/cm2, the polymers were found to have properties as seen in natural polymers like Xantha and were resistive to salinity as well. The detailed report would be summarized in the paper. It is interesting to note that the different species of microbes used were anaerobic and was suited to survive at temperature of up to 600° F thus making it possible for them to survive harsh environments. Thus an overall promising outlook providing alternative to expensive chemical floods is being presented with special application to depleted reservoirs.
The Feasibility Study of Replacing Oil Based Mud with More Environmentally Acceptable Paraffin Based System in Iranian Oil Fields
Authors: Vajargah A. Karimi , Tahmasbi K. , Arsanjani N.
Published: December 2009

As concerns about hazardous effects of using conventional Oil Based Mud (OBM) have been intensified in Iranian offshore fields, companies are looking for environmentally acceptable substitutes that possess the technical advantages of OBM and remain in satisfactory price range. One of the highest prospects, as an alternative for OBM, especially in deep water and deviated offshore drilling, is Synthetic Based Mud (SBM). Paraffin is a type of synthetic fluid that can be extensively utilized in Iran due to its lower cost and availability with respect to other types of synthetic fluids. Developing a suitable, less expensive formulation for this innovative system by relying on local products is highly demanded.

In this study, feasibility of replacing OBM with more environmentally acceptable Paraffin Based Mud (PBM) was investigated. Suitable formulations for PBM at desired operational ranges of temperature, Mud Weight (MW) and Synthetic to Water ratio (S/W) were developed. In addition, Rheology properties and Electrical Stability (ES) of the systems were measured. To examine mud stability under down-hole conditions, each system was hot rolled for 16 hours. The filtration characteristics of each mud sample were determined by means of a High Pressure High Temperature (HPHT) filter press. Furthermore, Shale recovery was evaluated, using highly reactive shale samples of KAJDOMI formation. The effects of possible contaminants in the system were also studied. Confirmation of the obtained results was conducted by comparison of PBM with similar conventional oil based packages.

Laboratory results indicate that from technical points of view, conventional OBM can be replaced with PBM in Iranian offshore fields since it suppresses environmental concerns and can provide technical advantages of OBM with reasonable cost. Comparisons of PBM with OBM show that rheological properties and shale recovery were approximately identical, while PBM represented higher ES and lower filtration rate that illustrates its better emulsion stability.
Modeling CO2 Storage in Aquifers: Assessing the Key Contributors to Uncertainty
Authors: Sifuentes W. , Blunt M. J. , Giddins M. A.
Published: December 2009

We study the influence of different physical properties on the effectiveness of CO2 storage in aquifers. We present the results of a numerical sensitivity analysis using experimental design to quantify and compare the contribution of the most important parameters to the trapping of CO2.

The work focuses on the impact of dissolution and residual trapping. Simulations using a reservoir model with properties and geometries representative of the Stuggart Formation in Ketzin (Germany) demonstrate how different trapping mechanisms are influenced by gravity segregation, fingering, and channeling.

These studies show that horizontal permeability is the most influential parameter on the total amount of CO2 dissolved, as it facilitates the lateral migration of CO2, enhancing dissolution into the brine. Residual gas saturation Sgr is found to be the greatest contributor to the amount of residual CO2. As expected, higher Sgr will reduce CO2 mobility, producing a higher residual trail left by the CO2 plume as it migrates. In addition, permeability heterogeneity is a major contributor to both trapping mechanisms.

After a suitable geological site for CO2 storage has been selected, our studies suggest that with appropriate well placement and injection strategy, at least 80% of the stored CO2 can be trapped within a few decades of the end of injection.
Recovery of Bypassed Reserves Above Top Packer Using Innovative Cement Packer and Through Tubing Add Perforation
Authors: Seng Wong Chun , Wahib Suhaila , Jiun Choo Der , Ramnarine Ronald , Jumaat Mohd Shafie
Published: December 2009

West Lutong is a mature field with 8 rounds of field development campaigns and close to 40 years of production. Currently, only 50 % of total strings are flowing. However, the idle wells could possibly access undeveloped marginal reserves in shallow reservoirs. These shallow reserves are located above top production packer as they were not previously included in initial completion due to historical sand problem

Following West Lutong Full Field Review in 2006, presence of by passed potential reserves above top production packer were confirmed. Conventional workover rig to re-complete these potentials is not economically viable due to significant cost and complexity. An innovative, rigless "cement packer" approach, had been chosen for the pilot job in Well # A, while retaining necessary level of completion integrity. The proper placement of cement packer approach involves usage of hydrostatic sequence valve as choke manifold to prevent U tube effect. Numerous down hole problems such as wax, scale, sand and fish from insert string had been rectified using appropriate coiled tubing solutions. Conventional E-line perforation using high density shot gun and deep penetrating charges were then used.

Well # A had been producing, under controlled condition, average 930 bopd without sand problem for 10 months since July 2008 with 1.10 MMstb reserves monetized. The total cost was only 10% of a conventional workover.

This paper shares a detailed case study of Well # A in term of candidate's selection, reserves estimation, cement packer execution, lessons learnt, and future recommendations. It is evident that cement packer technology is feasible and economic for accessing by passed reserves above existing production packer.
Optimizing Chalk Reservoir Development Using Detailed Geophyiscal Characterization: The Halfdan Northeast Field, Danish North Sea
Authors: Henriksen Karen , Gommesen Lars , Hansen Hans Peder , Kistrup Jens P. , Steekelenburg Christa
Published: December 2009

The Halfdan Northeast gas field is a widespread, thin accumulation in high porosity, low permeability chalk of Danian age. Successful development relies on implementation of long single- or multilateral horizontal wells in thin reservoir zones and securing the maximum number of reservoir feet for each well bore. Consequently, detailed knowledge of reservoir geometry and properties is essential. This paper describes how the detailed reservoir architecture was resolved by geophysical reservoir characterization based on rock physics understanding using optimized seismic elastic inversion products.

The chalk reservoir is difficult to distinguish from the overlying shale on conventional seismic as the effects of porosity and gas/fluid mixture cause the reservoir chalk to exhibit similar acoustic impedance as the shale above. The placement of wells is further challenged by the fact that erosional depressions, ranging in size from ca. 400 to 6,000 metres across, are present in the chalk. Optimized elastic inversion allowed mapping the top of the continuous chalk and the base of the overburden shales, whereby the infill of these structures could be characterized, consisting of marl and disturbed chalk. A well targeting the disturbed chalk infill confirmed this interpretation and found it to be of reservoir quality. The further development strategy is to tap both the laterally continuous chalk and the disturbed chalk bodies to maximize recovery.
Full-Azimuth Marine Acquisition Using the Coil Shooting Technique
Authors: Brown Gordon , Palmer Ed
Published: December 2009

In this paper, we describe a new single-vessel full azimuth (FAZ) seismic acquisition technique named Coil Shooting*. Whereas conventional marine 3D seismic acquisition records only a narrow azimuth of seismic traces, this new technique acquires FAZ data. We show data examples from extended field trials, review data processing challenges such as noise removal and multiple attenuation, and discuss survey design.

The Coil Shooting technique is a development of wide-azimuth (WAZ) acquisition. Over the last five years WAZ has been used extensively in the Gulf of Mexico to produce enhanced images in the subsalt section. However, WAZ marine acquisition using towed-streamer technology still requires the use of multiple vessels (typically three or four vessels). In the North Sea and surrounding areas there are significant advantages in deploying a single vessel, as multivessel operations are subject to availability and logistical constraints. FAZ acquisition records over the full range of azimuths and offsets. In the case of Coil Shooting, this is achieved by sailing the vessel in a series of circles or coils.

WAZ and ocean-bottom cable seismic operations are proven techniques for improving illumination. Results from recent modelling and field tests demonstrate that the Coil Shooting technique has similar capabilities.

Although the idea of recording while sailing in circles dates from the 1980s, Coil Shooting requires modern streamer positioning and control techniques. We demonstrate that limitations from the 1980s have now been overcome and show that FAZ recording has the potential to improve imaging of geological structures that continue to cause interpretation problems in the European continental shelf, e.g., subsalt, salt flank, and Jurassic tilted fault block structures.
Offshore Crew Supply–Modern Marine Options Challenge Helicopters
Authors: Brittan D. , Douglas S.
Published: December 2009

The helicopter has long been regarded as the default choice for crew supply due to its speed, flexibility and passenger comfort. Marine crew transportation has until recently being regarded as slow and more hazardous. Three specific technological advancements, high speed hull design, DP2 automatic vessel station keeping and advances in transfer capsule design, now offers high speed marine crew supply, with levels of passenger safety and comfort that exceed helicopter transfers. Utilizing the ‘state of the art’ CrewZer Class vessel, this new crew supply solution is leading many operators to re-evaluate their crew supply options.

A good crew supply solution should provide high levels of safety, speed and reliability, as well as operational flexibility. As offshore development cost rise and other assets mature, there is increased pressure to reduce operating costs, whilst attending to crew welfare and morale. The CrewZer access solution can deliver up to 30% savings on logistical costs, whilst enhancing safety or passenger welfare.

The first CrewZer Class vessel, the Seacor Cheetah (the fastest offshore support vessel ever built) was introduced to the market in February 2008. Voted ‘American Ship of the Year’, it has an aluminum catamaran hull, capacity for 149 passengers and a cruising speed in excess of 40 knots. It's DP2 station-keeping and wide stable hull provide an ideal platform for personnel transfer operations. The vessel also utilizes a custom designed 9-passenger advanced transfer capsule. The entire system is expected to provide one of the safest crew transfer solutions in the industry. This integrated solution provides the following additional benefits:- An ideal emergency evacuation tool (e.g. hurricanes), capable of the rapid evacuation of large crews. This allows operators to delay evacuation decisions, possibly avoiding unnecessary shut downs, without compromise to safety.A high speed vessel suitable for early response to offshore fire, equipped with two large fire monitors.150 ton of deck load optimized for fast track logistic support.Enhanced vessel stability which increases the operational weather window for transit and loading operations.

After over a year in operation and tens of thousands of successful transfers, the system has been thoroughly field proven. This paper describes the system in full, the experiences of the first year in operation and goes on to explore likely future developments in crew supply operations.
Investigation of Production Tubing Coupling Failures From a Suspended HPHT Well
Authors: Hillis David J. , Eddy Michael , Cassagne Thierry , Ligertwood John
Published: December 2009

The challenging nature of high pressure high temperature (HPHT) oil and gas production wells has necessitated the development of new technologies and the use of high performance materials and fluids. Inevitably, this has resulted in some unexpected phenomena and field failures have been responsible for stimulating research into several aspects of corrosion and environmental cracking associated with HPHT production.

This paper details the investigation of production tubing coupling failures, which occurred during the retrieval of cold worked 25Cr duplex stainless steel production tubing. The tubing had been present in a suspended well for two years and was being retrieved as part of a workover operation. The investigation was conducted to determine the nature of the failures and identify contributory factors and has resulted in recommendations for long term use of formate brines at high temperature.
Harding Central–Achieving 74% Recovery
Authors: Zhang P. , Green S.
Published: December 2009

Harding Central is a high permeability turbidite reservoir in the Central North Sea. It has been produced with water injection for pressure support and gas injection for disposal of evolved gas since 1996. The initial oil in place has been tightly constrained by high quality seismic, high density of well penetration and various dynamic data. The production data show that we have already recovered 70% of the oil initially in place by end of 2008. We expect the reservoir to achieve 74% recovery without further infill drilling by the end of field life.

We attribute this extremely high recovery factor partly to high rock quality with low Sor, and more importantly to the good understanding and effective management of the reservoir. This paper will summarise key methods by which we have achieved such a high recovery factor, namely (1) good well design and placement to ensure high rate and avoid early coning; (2) 4D seismic used to manage fluid contacts and identify unswept area for infill targets; (3) repeated GOC logging to underpin reservoir management strategy; (4) solid reservoir engineering to support business decisions; and (5) stable production.
North West Hutton: Decommissioning the North UK's Sea's First Large Platform With a Fixed Steel Jacket: Topsides Removal
Authors: Farrow Chris R. , Harris Glyn , Groot Jan
Published: December 2009

During the summer of 2008, Heerema's semi-submersible crane vessel Hermod and a small fleet of transportation barges successfully removed the topsides modules from the North West (NW) Hutton platform. The NW Hutton platform was commissioned in 1983 and lies in the northern North Sea in 143m of water roughly half way between Shetland and Norway. The 17,000 tonnes eight leg steel jacket supported a modular topsides with a combined dry weight of approximately 20,000 tonnes. Removal of NW Hutton represents one of the most challenging decommissioning projects tackled by the offshore industry to date.

This paper describes the preparation phase and actual removal of the topsides, including the associated transportation and load-in phases. Topics covered include: History of N W HuttonDecommissioning PhilosophyNormally Unmanned Installation PhaseTopsides Removal; Engineering and its ChallengesTopsides Removal and Transportation; Execution of Work and its ChallengesKey Lessons

Overall the topsides removal project was completed safely with no significant Health Safety or Environmental issues despite the very significant offshore scope. Success factors included: A dedicated client team ensuring compliance with standardsPre-agreed go/no go gates and the authority for those gatesextensive planning,detailed on-site reviews, andclose co-operation between HMC and BP.
The First all Electric Subsea System on Stream: Development, Operational Feedback and Benefits for Future Applications
Authors: Gerardin Pierre , MacKenzie Rory , Van Den Akker Jan
Published: December 2009

In September 2008, Total E&P Netherlands BV and its partners started up production from K5F field with the first all electric subsea production system. The field is located in the Dutch sector of the North Sea, and is tied back to a platform (K6-P/C) located18 km away. The K5F development consists of a manifold designed for 3 wells and a potential step out. Initial installation includes 2 subsea X-Trees with associated controls.

The all electric system uses the concept of end to end redundancy, consistently from surface to the subsea actuators, with the objective to maximize operational availability. The system uses high voltage DC electrical supplies, to minimize power losses and umbilical cross section. The system does not rely on batteries or accumulators and hence allows unlimited actuator operations. The true environmental friendly design fully complies with the Zero discharge concept.

The joint paper will describe the experience gained during development, qualification and commissioning, as well as the system operational performance during the first period of production. Operational results will be evaluated against key initial objectives: Simplification of subsea control systemImproved monitoring of system status and condition

The paper will also discuss the following inherent advantages of the all electric technology applied to subsea production systems: Increase in potential field offset distanceReduction of umbilical size, complexity and cost

Consideration will be given to the benefits of this technology when applied to HIPPS systems and deepwater subsea processing applications for which fast acting subsea process control valves may be required: Significantly reduced valve actuation timeIncrease in reliability and availabilityEnhanced monitoring allowing superior process control
A Practical Methodology For Evaluating Appalachian Basin Waterfloods
Authors: Freeman David C.
Published: December 2009

The Appalachian Basin, the oldest domestic United States producing area, is home to a number of active waterfloods and even more waterflood candidates. Efforts to evaluate existing floods and assess new opportunities, however, are often hampered by scant reservoir rock and fluid data, as well as incomplete, or nonexistent, fluid production and injection records.

The purpose of this paper is to illustrate, through the study of a case history, a practical methodology for evaluating a 30-year old Appalachian Basin waterflood, beginning with culling original in-house documents and well files and concluding with numerical simulation. The studied flood is the Richardson Unit Waterflood (Calhoun and Roane Counties, WV).
Swellable Packers in Unique Horizontal Completions Solves Difficult Challenges in Offshore India Vasai East Field
Authors: Kalyani Tejas , Avtar Ram , Srivastava A. K. , Singh Ram Suresh , Badwaik D. Z.
Published: December 2009

Oil and Natural Gas Corporation (ONGC) operates the Vasai East Field in western offshore India. The reservoir is challenging to drill and complete because of the inherent risks of gas and water coning, permeability differences, and declining reservoir pressures. An innovative horizontal completion strategy for new wells to meet the many unusual challenges was required. The need for appropriate zonal isolation was identified after the wells in the Vasai West Field had been completed without segmentation in the open hole. The requirements included:

Oil production without breakthrough of gas or water Effective hydraulic seal in washed-out hole conditions Contingency options for intervention, if needed Equipment to withstand high bottomhole static temperature.

This paper describes how the challenges were met using swellable-packer, high-temperature isolation systems placed between perforated tubing/sliding-sleeve circulating devices and blank pipe spaced out across the oil-bearing zones. The swellable packer systems were located at the ends of each facies change to isolate the local high-permeability zones. Swellable packers use expanding rubber around the packer mandrel that expands to seal the annulus and create a permanent seal when it contacts liquid hydrocarbon or water in both cased or openhole environments.

Five wells have been completed in Vasai East field to date with swellable packers in conjunction with pre-perforated liners or sliding sleeves. PLT logs have been run in one of the wells post completion, and isolation has been verified. Low water cuts and low gas/oil ratios (GOR) also verify that the packers isolate the various sections of the wells as planned. On the success of these completions, this technology is currently being planned for ONGC's completions in other fields.
Expandable Liner Hanger Drill-in Capability Provides Reliable Solution for North Sea Case History
Authors: Montañez Carlos Mario , Jensen Søren Lundgren , De Clute-Melançon Daniel
Published: December 2009

The combination of unstable, highly pressured formations overlaying depleted reservoirs or low-pressure formations continues to challenge the drilling of oil and gas wells. A primary concern is the possible collapse of the formation due to the lack of mud weight window resulting in stuck pipe and incapability to run casing to depth, significantly impacting operational cost.

One identified and proven solution for this challenge is the implementation of a "Drilling with Liner technique" (DwL). If the formation collapses during this operation, the casing is already in place, and thus, the weak formation is cased off.

Due to the challenges intrinsic to DwL, the need for specialized drilling tools with sufficient mechanical capabilities such that the formation becomes the only limit has been identified.

This paper will discuss one of these specialized drilling tools – an Expandable Liner Hanger (ELH) that has elastomeric elements bonded on to the hanger body. As the hanger body is expanded, the elastomeric elements are compressed and sealed against the casing. This provides gas tight liner-top pressure integrity as well as delivering impressive tensile and compressive load capacity on setting. The system can be set up for liner drilling, which enables the liner to be drilled into the low pressure reservoir, cemented, and the liner top to be isolated upon setting.

Recently, an operator in Denmark used an ELH in combination with a liner to successfully drill into a formation that had caused problems in previous attempts. Advances made to an ELH system to address the various contingency activities, job planning methodology, activities that took place, and lessons learned from the job will be presented.
Wellbore Instability Predictions Within the Cretaceous Mudstones, Clair Field, West of Shetlands
Authors: Narayanasamy R. , Barr D. , Milne A.
Published: December 2009

Wellbore instability within Cretaceous mudstones overlying the Clair oilfield has prevented successful drilling of high-inclination wells in the past. Detailed investigations of the possible reasons for borehole failure led to a decision to cut two cores within the unstable interval and carry out laboratory testing to investigate the failure mechanism. Analysis of rock failure based on a "planes of weakness" theory fitted previous drilling observations. This theory has been applied primarily for layered hard rocks (e.g. mining and tunneling) and is here extended to significantly weaker mudstones showing strength anisotropy. Minimum required mud weight predictions were made for a range of well configurations. The results of this study were used to plan an Extended Reach Drilling (ERD) development well targeting a previously undeveloped part of the Clair field. The new well was successfully drilled, cased and brought on stream within budget, in 2009.

This paper describes the basic geology of the field, rock properties of the Cretaceous mudstones, details of laboratory tests conducted and analyses carried out. Cretaceous mudstones of the Clair field are characterized by low strength and minor anisotropy. Various rock tests were conducted on core to define their failure behavior: Unconfined Compressive Strength (UCS), single-stage triaxial strength and multi-stage triaxial strength tests were conducted, all at various angles to bedding. In addition, the effect of mud invasion was analyzed by performing a multi-stage triaxial test in drilling mud at high pressure. The analysis used commercial software to evaluate borehole instability in a rock medium that fails along weak planes. Minimum mud weight requirements derived from this analysis were compared with previous drilling experience and subsequently used for predicting mud weight required to drill an ERD well. Lessons learned from the successful drilling of this well will be applied in future Clair development wells and may be of relevance elsewhere.
Produced Water Management in Mature Field Operation
Authors: Hansen Lars Hvejsel
Published: December 2009

From 2002 to 2008 the oil discharge has been reduced by 10% despite an increase in the produced water discharge of 230% (Figure 1). This has been achieved by reducing the average oil concentration in the produced water to 9 mg/l in 2008. Significant reductions have especially been recorded from 2007 to 2008. The reductions are primarily a result of the following initiatives.

Rerouting of recycles - rerouting of e.g. used H2S scavenger have improved separation and produced water treatment Individual KPI's for the different produced water treatment systems On-line cleaning of the produced water treatment systems System analysis - continued optimisation of the separation and produced water treatment systems

This paper presents the significant reductions that have been achieved primarily through technical improvements and better operation of the installed equipment.
CO2-Brine Surface Dissolution and Injection: CO2 Storage Enhancement
Authors: Eke Paul Emeka , Naylor Mark , Haszeldine Stuart , Curtis Andrew
Published: December 2009

Carbon capture and storage (CCS) is capable of reducing atmospheric emissions of greenhouse gases from coal or gas fired power plants. The upward buoyancy of dense phase carbon dioxide (CO2) in deep reservoirs means that sites need to be chosen with a methodology which has carefully evaluated details of performance during and after the injection process. Standard methods of site evaluation for saline aquifers focus overwhelmingly on the aspects of geological containment and monitorability. Also important to storage site performance is the engineering design of transport and injection. Transport to storage in offshore saline aquifers is normally expected to be by pipeline. There are several proposed methods of CO2 injection, for example as a dense phase, in the liquid or supercritical phase, as water-alternating gas cycles, or as carbonated brine. These result in different migration pathways in the aquifer during the short term (1-50yr) and storage distributions in the long term (1,000 – 10,000 yr). To develop a methodology suitable for making informed decisions for aquifers offshore of the UK, several of these different methods are being evaluated. A chemical engineering and reservoir engineering approach will be used to define some of the important surface transport and subsurface interactions. Important surface features may include the energy balance, location, sizing, materials specification and costing of surface equipment for mixing and transporting CO2.
Pipe Rotation Improves Hole Cleaning and Cement-Slurry Placement: Mathematical Modeling and Field Validation
Authors: Moroni N. , Ravi K. , Hemphill T. , Sairam P.
Published: December 2009

Placing the cement slurry in the entire annulus, in both the wide and narrow sides, is essential to achieving effective zonal isolation. Well conditions, such as deviated wellbore geometry, eccentric annulus, and gelled drilling fluid, pose unique challenge in achieving this objective.

It is known in the industry that pipe movement helps improve hole cleaning and cement-slurry placement. However, the quantitative effect of pipe rotation on hole cleaning and cement-slurry placement for a given eccentricity, flow rate, and geometry was not well studied. Hence, it was difficult to design a primary cement job where the effects of all these parameters were considered at the same time and optimized for best results.

The effective velocity and pressure drop in an eccentric annulus with and without pipe rotation is modeled for Herschel-Bulkley fluid. This is then extended to evaluate the effect of pipe rotation on hole cleaning and cement-slurry placement. The modeling clearly demonstrates the improvement in hole cleaning from pipe rotation in an eccentric annulus. Now there is a tool available to study the interaction of various factors on hole cleaning and optimize them for the well in question.

The results from the modeling study have been compared with field data. The comparisons show a good match between the improvement in cement-slurry placement predicted that was inferred from the cement bond logs. The study clearly indicated the importance of using representative rheological model and input values.

The modeling results and field validation are presented and discussed. The work presented in this paper should help the industry optimize the various factors during a cement job to help maximize hole cleaning and cement-slurry placement in the wide and narrow sections of the annulus. This should help in achieving zonal isolation for the life of the well and reduce operating expenses by reducing remedial jobs.
Platform Re Design for CO2 injection: Process and Safety Engineering Challenges
Authors: Hargreaves John H.
Published: December 2009

There has recently been Conceptual and FEED studies to convert existing hydrocarbon producing facilities to CO2 injection. Often the most cost effective option for CO2 injection is when combined with enhanced hydrocarbon recovery. This new operation, however, increases levels of risk; the additional CO2 gives rise to a new asphyxiate hazard, while the increased CO2 in the Process stream brings its own production and safety trade-offs. This paper addresses these hazards and the conundrum of optimising production and safety. Presented herein is an integrated Process and Safety Engineering approach to control the risks and develop a decision making framework to allow confidence for the safe design of future CO2 injection Projects.
Advanced Treatment Solutions of Sewage- and Bilge-Waters Onboard Offshore Installations
Authors: Rosebrock Andreas
Published: December 2009

With the new IMO regulation MEPC 159(55) coming into force by January 2010 for sewage treatment plants, more stringent limit values have to be considered for certain effluent parameters also in the offshore industry. Proper sewage treatment system design is of course the first step and a prerequisite to avoid operational problems, environmental pollution, and also to safeguard operating staff. However, with the new regulation coming into force and an increasing number of sewage treatment plants been developed and are brought to the market by various manufacturers, owners ask themselves: what is the proper product and reliable technology to meet our individual requirements?

The objective of this presentation is to generally inform about new IMO MEPC 159(55) regulation, its effect on the offshore industry and to provide an overview and comparison about certain technologies available. The second part of the presentation will discuss the treatment of bilge waters in the offshore industry. Here again with general information about the respective IMO regulation MEPC 107(49), and also with an overview and comparison about certain technologies available.

The conclusion will also include an outlook on possible future developments in the field of sewage and bilge water treatment.
Case History: Recompletions in a Virginia Coalbed-Methane Field Yield Additional Gas
Authors: Rodvelt G. D. , Moyers W. L. , Malamisura P. R. , Hagy C. W. , Greer S.
Published: December 2009

The domestic United States has more than 30,000 coalbed-methane (CBM) wells drilled and producing. The majority of these are vertical, producing wells that have been completed with hydraulic fracturing to access coal-seam gas. Mature CBM fields can still provide an opportunity to deliver more gas production. While incomplete primary-stimulation and additional-pay intervals can be easily identified as candidates, wells with scaling issues, fines invasion, or proppant production can be more difficult to ascertain. Determining the best recompletion solution requires an integrated review of the well history from its construction through completion as well as each well’s production profile.

This paper describes the methodology used for determining which wells to recomplete in a 30-well program in 2007. Four types of recompletions were established with at least three wells in each category, allowing comparison of different recompletions methods. A diagnostic approach is described that determined the proper course of action as field work confirmed the well problem. After at least 12 months of post-treatment production, this project was deemed a success with an uplift greater than 10 Mcf/day on 63% of the wells and 403 MMcf in additional gas sold to market.
Optimizing Openhole Completion Techniques for Horizontal Foam-Drilled Wells
Authors: Allison Dave , Folds Don , Harless David , Howell Matt , Vargus Greg , Stipetich Abby
Published: December 2009

Over the last two years the increase in openhole interventionless horizontal completions in the shale markets has lead to higher production rates at lower completion costs for operators. In areas where wells are being air-drilled, specific techniques of using hydraulic set packers and sliding sleeves has proven to be a viable, low-cost, interventionless solution to complete when the wells are likely to be a gauge hole. However, in areas where the horizontal wells use foam instead of air because of the sensitivity of the shale, typically the wellbore is non-gauged and may lead to operational failures when trying to isolate the wellbore with hydraulic set packers because of the limitation of the expansion of the element package. The advances in the use of swellable elastomer packers provide an ideal solution for isolating these non-gauged holes for the completion process. But, as mentioned, there is sensitivity to the shale in these wellbores, and applying the typical hydrocarbon fluid to the formation to swell the swellable elastomer packers may cause a detrimental effect to the formation.

To overcome the issue of isolation in non-gauged holes without damaging the shale formation, an interventionless solution was incorporated using sliding sleeves, swellable elastomer packers, and development of a new shale optimized fluid system to swell the packers. The shale-optimized fluid is an effective low-leakoff fluid that causes minimum physio-chemical damage to the shale while increasing the optimization of the swell time of the packers. This paper will discuss the development of this new completion process for use with foam-drilled openholes that are non-gauged and case history information of applications that have been run in the Lower Huron shale formation.
Boundary Element Analysis of the Stress Distribution Around Multiple Fractures: Implications for the Spacing of Perforation Clusters of Hydraulically Fractured Horizontal Wells
Authors: Cheng Y.
Published: December 2009

For multi-stage hydraulic fracturing of horizontal wells with casing hole completion, multiple cluster perforations are typically used to create multiple fractures in any single stage. How to place these perforations is a critical issue because the number of perforation clusters to be used and the space between them significantly impact how effective the fractures can be created in the formation. To optimize the spacing of perforation clusters, stress distributions and fracture mechanics need to be well understood.

In this study, the displacement discontinuity method is used to construct a boundary element model, which is able to analyze the stress distributions around multiple transverse fractures and the geometries of these fractures. With the boundary element model, multiple cases are investigated for different number of fractures and fracture spacing. Changes of both minimum and maximum stresses, as well as shear stress around these fractures are first illustrated. It is found that for the cases with more than two parallel fractures, there is a strong stress concentration around the center fractures. The calculated displacements indicate that the created fractures are no longer elliptic-like, and the widths of the center fractures are significantly reduced compared with that of a single fracture. For the case of two parallel fractures, the stress concentration between two fractures also results in the asymmetrical shape of fractures, but the fracture widths are not reduced significantly.

The study indicates that the number and spacing of the fractures need to be carefully selected in order to create effective fractures with appropriate fracture geometries. The boundary element model provides a useful tool to relate rock geomechanic properties to stress distribution and fracture geometries for multiple fractures in hydraulic fracturing of horizontal wells, which can be served as a guidance to space the perforation clusters.
Reservoir Simulation and Uncertainty Analysis of Enhanced CBM Production Using Artificial Neural Networks
Authors: Jalali J. , Mohaghegh S. D.
Published: December 2009

Coalbed methane is becoming one of the major natural gas resources. CO2 injection into CBM reservoirs is used as an effective method for CBM production enhancement (ECBM) and for long term sequestration of CO2 (CO2Seq). Reservoir simulation is used regularly for building representative ECBM and CO2Seq models. Given the wide range of uncertainties that are associated with the geological models (that forms the foundation of any reservoir simulation), comprehensive analysis and uncertainty quantification of ECBM and CO2Seq models become very time consuming if not impossible.

This paper addresses the uncertainty quantification of a complex ECBM reservoir model. We use a new technique by developing a Surrogate Reservoir Model (SRM) that can accurately mimic the behavior of the commercial reservoir model.

Upon validation of SRM, we perform Monte Carlo Simulation (MCS) in order to quantify the uncertainties associated with the geological (CBM) model. Performing MCS requires thousands of simulation runs that can be performed easily once the SRM is developed. Key Performance Indicators (KPI) of the simulation model are identified to help reservoir engineers concentrate on the most influential parameters on the model’s output when studying the reservoir and performing uncertainty analysis. Unlike conventional geo-statistical techniques that require hundreds of runs to build a response surface or a proxy model, building an SRM only requires a few simulation runs.
Using Microseismic Monitoring to Better Understand Completion of the Medina - Whirlpool Formations: A NYSERDA - Sponsored Project
Authors: Walker Kirby , Sink John , Le Calvez Jöel , Frantz Joe , Martin John
Published: December 2009

The Medina is a group of Silurian-age sandstone formations that have been dependable gas producing zones in Western New York since the late 1800’s. Most of the production from the Medina has come from a combination of the Whirlpool and Grimsby formations. The method of how to most effectively complete these two formations is an ongoing topic of debate. The formations are separated by the Cabot Head shale formation that ranges in thickness from less than 5 feet to more than 70 feet in some places. One of the main questions with regard to completion of these formations is whether to 1) stimulate the Whirlpool and the Grimsby with separate treatments to ensure effective stimulation of both layers; or 2) stimulate both formations with one hydraulic fracture treatment, at a lower cost, that grows from the Grimsby through the Cabot Head and into the Whirlpool.

Microseismic monitoring of hydraulic fracture treatments is now a proven technique used to analyze hydraulic fracture geometry and azimuth. The New York State Energy Research and Development Authority funded a project in Chautauqua County, New York to use this technology to monitor a hydraulic fracture treatment in a Grimsby/Whirlpool well for the purpose of understanding hydraulic fracture development in these formations.

This paper uses the microseismic results obtained from the study to validate a hydraulic fracture model of the Grimsby/Whirlpool formations. A sensitivity analysis was then performed using this hydraulic fracture model to give direction as to when the Grimsby and Whirlpool formations should be stimulated simultaneously and when a two-stage completion would be more beneficial to obtain an effective stimulation in both zones.
A Fast, Fully Integrated Approach to Early Field Development Resource Evaluation and Value Assessment: Madu-Anyala Project - Nigeria
Authors: Okoro Innocent , Krolow Jennifer , Novakovic Djuro , Aladesulu Adeniyi , Reynolds Kendall , Adetifa Abbey , Ikelua Emmanuel , Ajayi Foluso
Published: December 2009

Significant reserves and production growth are often achieved by bringing green fields onto production. Green field development is an intricate process and the quality of activities and decisions taken in the early stages significantly impact project value. Poor definition of the field resource base and the lack of practical, cost effective development options are a sure road towards value erosion. Thus a critical aspect of the development process is the evaluation/validation of the project resource/reserves base from which the key project economic parameters are determined. Resource evaluation for New Field Developments has changed dramatically over the past decade as no longer is "the answer" obtained by building and testing one or two deterministic models.

Modern Major Capital Projects are expected to develop fully probabilistic production forecasts and ranges of Original Oil in Place (OOIP) and Reserves in order to assess the entire project value profile. Typically, this involves creating multiple static earth models representing different geologic realizations coupled with a range of possible dynamic reservoir and operating conditions to yield numerical simulation models. Attempting to generate probabilistic forecasts one combination at a time or even with the application of structured uncertainty assessment techniques such as Design of Experiment (DoE) could easily push the project's evaluation time to months, sometimes even years. The dilemma thus becomes how to make a complete project go/no-go decision with the right amount of technical rigor while avoiding long resource evaluation cycle time on projects that potentially may not move into execution. In this increasingly resource constrained environment, both in terms of personnel and funding, there is need for a faster, better suited way to understand the key value drivers and the range of project value early in a field development. The approach presented here preserves technical rigor while leading to quicker, more efficient project (go/no go) decisions.

The Madu-Anyala Development Project investigated a cluster of 14 reservoirs in a joined development. Application of a streamlined method of earth modelling, in combination with integrated dynamic modelling of subsurface, wellbore, and surface conditions in a systematic manner described in the paper, provided probabilistic Original Oil in Place, recoverable reserves, and three-phase production profiles with a cycle time of only 4 months. The profiles, along with the concurrently generated facilities and drilling cost estimates, allowed for a fast, but reliable, assessment of project value early in the development.
Novel through Tubing Sand Control Solution for Failed Gravel Pack- Alpha Well -4L case Study
Authors: Yahaya I. O. , Opusunju A , Ajaraogu B , Agbogu G , Williams O , Uchendu C. , Udeh M , Oyetade T , Bakare M
Published: December 2009

Alpha field is situated in SPDC's OML 22 in the eastern part of the Niger delta belt, some 60kM NW of Port Harcourt. The field discovered in 1986, currently has 9 wells completed and 13 drainage points. Well A-4L is one of the completed intervals on the S7000E horizon. Production from this interval began in April 1997 and oil recovery averaged 2000 STB/D. Sand production was anticipated under normal drawdown from production onset and as such the well was completed with sand-control measures in place.

After about ten years of production, a significant amount of sand was observed during routine sampling of the well. This condition resulted in the closure of the well for high sand production.

To restore production from the well, current economic realities favored through tubing intervention. Two major types of through tubing remedial sand control solutions were considered namely mechanical and screen-less (chemical consolidation) methods. A proprietary HDR squeeze pack technique (mechanical method) was identified as the best solution that meets post intervention production requirements and also affords completion longevity. Total cost of deployment to recover 0.75MMbbl of oil was USD$0.650M compared to projected USD$5.0M for possible hoist re-entry.

This paper details the deployment process of this Novel solution that has successfully restored production from Well A-4L.