bluuebunny/crossref_metadata_2025 huggingface dataset:
Forensic Reservoir Characterisation Enabled With Underbalanced Drilling
Authors: Culen M. S. , Killip D. R.
Published: December 2007

Underbalanced (UB) drilling techniques are no longer being used simply to minimize reservoir impairment and improve access to remaining reserves in depleting fields. Traditionally archived and forgotten after the well was drilled, production data and reservoir information gathered while drilling underbalanced are increasingly gaining importance with oil and gas companies.

One Operator has been using UB technology in both clastic and carbonate reservoirs initially to maximize production through the minimization of reservoir impairment. Most of the operator's fields are supported by a weak aquifer or are under tertiary development through waterflood, and the task of water management is a growing concern. While minimizing reservoir damage is now a foregone conclusion when discussing UB operations, the ability to further maximize production through the ability to shut off water-producing zones is now a prime driver for drilling UB.

The comparison of ‘snapshot’ fluid production data during drilling offers a unique perspective on the well being drilled against geophysical LWD/MWD and post-drilling logging data. Temporal production data offers another piece to the reservoir makeup puzzle, and when placed alongside other available data allows reservoir engineers and geophysicists to forensically characterize their reservoir.
Processes Determining the Composition of Produced Water from Subsea Fields and Implications for Scale Management - Birch Field, UKCS
Authors: McCartney R. A. , Williams J. C. , Coghlan G.
Published: December 2007

Produced water analyses from the Birch Field, UK North Sea have been interpreted and combined with simulation results to explain the causes of changes in produced water compositions over time. Preliminary conclusions are that two formation waters are present in the oil leg, both trapped at the time of oil emplacement. Lower salinity formation water has been expelled from the Kimmeridge Clay Formation (KCF) and dominates shallower sections of the reservoir. Higher salinity formation water is thought to be ancient Brae aquifer water and dominates the deeper sections. Some lateral variability in formation water compositions is evident. Produced water from individual wells is a mixture of the lower salinity formation water, higher salinity formation water and injected water. Trends in produced water compositions over time reflect a relative decrease in formation water production and increase in injection water production. Depending on the constituent, reactions occurring as a result of injection of water into the reservoir also affect the composition of produced water. The results have challenged previous concepts relating to water production at Birch and will be considered in scale management plans in future. They can also be used to constrain reservoir simulations, to aid enhanced oil recovery decisions and to provide more reliable tracking of injection water and formation waters entering the production wells at Birch.

More generally, this study has demonstrated the importance of evaluating produced water analyses as early as possible after water breakthrough. Integration of reservoir simulation studies with the interpretation of produced water analyses can provide information that benefits scale management, STOIIP calculations, reservoir models, and tracking of injection water as well as providing analogue information that can help reduce uncertainties associated with the development of deep water and marginal subsea fields.
Optimizing Estimates of Probabilistic Reserves from Production Trends Using a Bayesian Approach
Authors: Jimenez E. A. , Idrobo E. A. , Ernandez J. , Startzman R.
Published: December 2007

The estimation of probabilistic reserves distributions is nowadays a mandatory task in the oil industry. The trade-off between speed and accuracy, coupled with the urgency of results is still making of Decline Curve Analysis (DCA) one of the most popular method to address these calculations.

In a previous paper, we introduced a quick and efficient application (PREP) to estimate probabilistic reserves distribution combining the advantages of stochastic methods (Bootstrapping) and DCA. Although the proposed tool is robust and effective, one of the limitations found was reconciling the statistical uncertainty associated in the generation of the DCA parameter distributions with the observed production trends.

The objective of this paper is to present a proficient procedure to reduce the uncertainties in DCA probabilistic reserves estimation via Bayesian techniques. The procedure allows the analysis of multiple decline trends taking full advantage of the self-learning capability implicit in Bayesian techniques. The usefulness of the results is maximized when coupled with proper reservoir knowledge, leading to statistically strong results.

The new methodology was applied in the reserve evaluation of three (3) Colombian fields located in the Valle Superior del Magdalena Basin in Colombia, South America. The method provided a new set of declination parameters with smaller covariance, reducing the uncertainty compared to any previous reserves distribution.
A Quantum Leap in Horizontal Gravel-Pack Technology
Authors: Mendez A. , Curtis J. , Evans B. , Farias R.
Published: December 2007

Proposal

Horizontal gravel packs typically employ heavy sand or ceramic gravels, laid down with un-gelled brines in the well-known alpha/beta wave sequence.As operators push the limits of horizontal open hole interval lengths, especially in low fracture gradient formations, it may become technically difficult or economically unfeasible to perform the gravel pack with conventional fluids and gravels.

Ultra lightweight gravels allow significant reductions in pumping rate (to avoid fracturing the formation), without risking premature settling and screen-out, therefore, longer wells can be treated.Higher gravel concentrations can also be used, even at low pump rates, resulting in drastic reductions in fluid volumes and treatment time, which is critical in cost-intensive offshore applications.In certain instances, the alpha wave can be eliminated, and the well packed directly in the beta wave mode, from toe to heel.

This paper summarizes the development and application of the ultra lightweight media and associated technologies for horizontal well gravel packing.Pioneering case histories will also be reviewed from the initial wells treated.
Case History of Breaking a Paradigm: Improvement of an Immiscible Gas-Injection Project in Buracica Field by Water Injection at the Gas/Oil Contact
Authors: de R. A. Lino U.
Published: December 2007

In May 1991 an immiscible carbon dioxide injection project began in the Sergi-C reservoir in the Main Block of Buracica Field. The injection has been performed in seven wells located in the upper part of the reservoir. Some time after the beginning of CO2 injection, the reservoir pressure increased and an increment of the oil production was attained. But, later on, the producing wells in the upper rows, beyond being the most productive wells, were also those that experienced the higher producing rates of CO2. This obliged for the shutting in of some wells and also the creation of a gathering system for the CO2 being produced, with the connection of the annular space of some wells to their pipelines. It was verified that the producing rate of gas and CO2 followed close upon the CO2 injection rate. Production data and simulation results have shown that the interruption or reduction of the CO2 injection would cause a significant reduction of the oil production. Due to the great demand for CO2 by new projects it was considered which would be the best way for ceasing the CO2 injection in the field, aiming at an increase in the supply of CO2 for other projects, but reducing its detrimental effect on the oil production. The adopted solution consisted in the creation of a water barrier for isolation of the CO2 cap. For this, seven wells closer to the gas-oil contact were chosen for water injection of a total rate of 2400 m3/day. The plan considers the interruption of CO2 injection when the water barrier is completely formed, which will take about 4 to 5 years after the beginning of the water injection. At that time the CO2 injection can be interrupted without impairing the project profitability. The water injection began in January 2002 and since then the project has been showing to be a success. The success can be seen by the increase in the oil rates and reservoir pressure and also reduction of CO2 production. The paper presents the main features of the project, as well as the results attained so far.
Chemical Water Shutoff Interventions in the Tunu Gas Field: Optimisation of the Treatment Fluids, Well Interventions, and Operational Challenges
Authors: Chenevière P. , Falxa P. , Alfenore J. , Poirault D. , Enkababian P. , Chan K. S.
Published: December 2007

Several Indonesian gas fields such as the Tunu field exhibit a specific behavior which causes a rapid decrease of the gas production. At shut in conditions, cross-flows from watered out layers to gas producing layers, were clearly identified as the major cause for gas production impairment.

The offloading of water from wells is performed at the preliminary stage of water production and often allows restarting the wells, but in a second stage it is ineffective. The nature of the damage in the gas-producing zones is not entirely understood but it seems to be a combination of at least two phenomena: (i) water adsorption on the high amount of clays present in these highly water sensitive layers (15 to 40 wt %) and (ii) water imbibition due to some capillary pressure experienced in the tightest layers (0.1 to 10 mD). Clay swelling or migration seems also to contribute for this damage but to a lesser extent.

Unwanted water along with gas and condensate production from several layers were quantified from multi-rate PLT, to define a strategy for well candidate selection and water shut off interventions. An inorganic gel was then selected to be selectively squeezed into the water-producing layers. The optimization of this fluid and of the preflush fluid required a complete qualification program which aimed at three main objectives: (a) maintain injectivity during the squeeze to allow an entire placement of the fluid, (b) provide, once set an extrusion pressure sufficient to withstand a significant drawdown and (c) gives a treatment's lifetime of one year minimum.

Three wells were treated in 2004, following the qualification of the fluids, the selection of candidate wells and the implementation of a complete treatment setup on a barge. This article describes the successes and the failures of some of them, pointing out the need for finely filtered fluids, low viscosity fluids and robust selective placement tools.
CO2 Energized Hydrocarbon Fracturing Fluid: History & Field Application in Tight Gas Wells in the Rock Creek Gas Formation
Authors: Gupta D. V. S. , Leshchyshyn T. T.
Published: December 2007

Gelled hydrocarbon has been used as a fracturing fluid from the early days of fracturing. Over the years, its use has diminished in the U.S. However, its use internationally continues to the present day in Canada, South America, Russia and East Asia. The paper will discuss the use of gelled oil fluids in Canada, particularly in low pressure tight gas wells, where the use of CO2-energized gelled hydrocarbon fluids has been very successful. The chemistry of these fluids and their application is discussed. The energized fluids have been used in a variety of formations and in wells of permeabilities from 0.1 mD to 10 Darcies, depths in excess of 3000 m and BHT from 10 to 110°C. Initial and longer-term production data from wells fractured with the energized fluid will be compared to wells fractured with conventional gelled hydrocarbon fluids to show the effectiveness of the system in tight gas applications.

The case study will include gas wells fractured and producing from the Rock Creek formation east of Edson, Alberta, Canada from 47-10W5 to 56-15W5 in the Western Canadian Sedimentary Basin (WCSB). Observations on proppant type and proppant amount are made in addition to comments on the fracturing fluid selection.
Scale Inhibitor Placement: Back to Basics—Theory and Examples
Authors: Sorbie K. S. , Mackay E. J.
Published: December 2007

Downhole scale inhibitor (SI) squeeze treatments are a common feature of the scale control plans of many oil operators. However, reservoir formations are large, heterogeneous rock bodies in which fluid flow is strongly determined by the permeability structure. Thus, when a slug of scale inhibitor is injected into the formation, fluid placement is an important issue. To design successful squeeze treatments, it is necessary to know where the injected fluid goes or, even better, we would like to control where the fluid package is placed in the near-well reservoir formation.

In this paper, we go "back to basics", in that we re-derive the analytical expression that describe placement in linear and radial layered systems for unit mobility and viscous fluids. In itself, this is not new since these equations are well known. However, we apply them in a novel manner to describe scale inhibitor placement. We also demonstrate the implications of these equations on how we should analyse placement both in the laboratory and by numerical modelling before we apply a scale inhibitor squeeze. We present an analysis of viscosified SI applications for linear and radial systems both with and without crossflow between the reservoir layers.

Visualisation experimental results are also presented of simple and viscosified slug placement in layered bead packs with crossflow between layers. It is shown that these agree very well with the numerical predictions. Additional calculations on near well placement in radial systems are also presented showing how the theory carries over into real field near-well, heterogeneous systems. Some novel ideas are presented on the application of viscosified scale inhibitor treatments.
Scale-Dissolver Application Under HP/HT Conditions -- Use of an HP/HT "Stirred Reactor" for In-Situ Scale-Dissolver Evaluations
Authors: Williams H. , Wat R. , Chen P. , Hagen T. , Wennberg K. , Viken V. , Graham G. M.
Published: December 2007

In several high temperature and high pressure (HT/HP) production environments severe downhole carbonate scale formation is often anticipated and effective carbonate scale dissolvers are required. However for most cases the selection of scale dissolvers is conducted under much less severe conditions, involving simple bottle tests conducted at temperatures up to 95°C and ambient pressure. These tests although generally accepted for screening purposes suffer a number of significant limitations. In addition to the moderate test conditions the low pressure means that carbon dioxide is readily released following the dissolution and results in changes in the test pH which may mean the efficiency of the dissolvers could be overstated.

This paper describes the use of a novel a novel HP/HT "stirred reactor" test rig to more closely examine the relative performance of selected scale dissolvers including organic acids (formic and acetic acids), inorganic acids (16% HCl) and other more conventional scale dissolvers under typical field application conditions. The equipment is specially designed for the extraction and stabilisation of samples at or ‘near’ tested conditions and therefore allows the equilibrium dissolution level to be determined under more representative HP/HT conditions. In this work preliminary tests were conducted using 16% HCl under progressively more severe test conditions (RT & 1,500 psi; 150°C & 1,500 psi and then 150°C & 4,500 psi. Further tests were then conducted to compare the performance of organic acid based scale dissolvers (formic acid and acetic acid based products) together with other selected scale dissolvers at 150°C and 4,500 psi and compared with the results obtained for 16% HCl. For these HP/HT tests, samples were collected and analysed after 2 and 20 hours equilibration time and results were compared with those obtained in more conventional "bottle tests conducted at less severe environmental conditions (90°C and ambient pressure).

In summary the results demonstrate the importance of conducting scale dissolver tests for field applications under more representative (HP/HT) conditions. Of particular significance was the impact of the cooling and pressure reductions. For one of the products tested, although very good dissolution was recorded under the HP/HT conditions, re-precipitation of a different polymorph of calcium carbonate occurred very rapidly resulting in a significant increase in the volume of carbonate precipitation within the reaction vessel and various sample lines. The paper will describe the details of the test equipment used in this work and present a mechanistic interpretation of the various results obtained.
The Challenge of Federation of Information for Automated Surveillance of ESPs: Field Examples
Authors: Theuveny B. , Kosmala A. , Cosad C. , Pulido F. , Destarac P.
Published: December 2007

Real Time Production is not just a buzzword today. A number of assets is experimenting implementations of real time production systems and some have made the leap of faith and rely extensively on it to optimze part of their production processes. A number of trial and errors have enabled to construct a number of rules of thumbs in the design, implementation and operation of such system. Because of the easy (or easier) case for value generation, the surveillance and optimization of artificial lift systems have been preferential targets for such implementations (in this paper we will focus on ESP operations).

One of the main operational issues related to the realisation of the value expect from this type of project is to ensure that all of the required information is correct. This is not a little feat!

This paper describes the challenge of the federation of the information required to perform automated surveillance of ESP in remote wells. The end-to-end delivery of reliable workflows requires the following elements: –Validated streaming real time information (pump measurements, intake and discharge pressures etc…)–Validated episodic information (well test flowrates, choke and back pressure information)–Static information (tubing size, formation parameters etc…)

The reliability of a real time production workflow in an automated system requires the insurance that all of these three types of information be correct.

The evaluation of the dependency of reliable information of information to the quality and reliability of the final surveillance information is demonstrated through the use of graph analysis. This methodology enables to focus the field data capture in the right areas, which are not always intuitive.

Field examples from South America demonstrate the value of such real time production workflows. Case histories also demonstrate instances of raising wrong alarms and the analysis of such event confirms the theoretical sensitivity analysis.

The paper concludes with a number of recommendations towards the field practices related to the real time enabling of the production operations some that can be extended to the futuristic full field automation.
Designing the Perfect Drilling Fluid Additive: Can it be Done?
Authors: Hall J.
Published: December 2007

The environmental and technical performance of drilling fluid additives is a key characteristic of such products. However, at times, the technical performance and environmental characteristics of materials used to make such additives seem to be at odds with each other. For example, materials that show good technical performance (stability) at high temperatures are frequently poor biodegraders, and those that are the most chemically active can show the highest toxicities.

In addition to the paradox of performance vs. environmental acceptability, international drilling fluids companies face diverse environmental regulations when operating in geographically distinct areas. Some of the most marked contrasts are observed when comparing regulations in the two most active offshore operating areas: the North Sea and the Gulf of Mexico. Regulatory discrepancies like these should be taken into consideration at the product design stage, when there is a potential for global technical performance to be sacrificed for environmental compliance in just one of the areas. One may be forced to ask which regional regulation should shape an additive's design? Are there oilfield chemicals that have been rendered unusable by regulations in one area while showing excellent economic and technical performance in another, without any apparent degradation of the environment?

This paper will discuss and present real-life examples of drilling chemicals that have been designed and often redesigned to fit stringent environmental criteria, according to the areas in which they are used.
The Development and Implementation of a Comprehensive System of Care in Remote Locations
Authors: Cram R. S.
Published: December 2007

Proposal

Operations in remote areas of the world are, by definition, a long way, either in time or distance, from a location where extensive medical care is available. Often, frontline medical facilities are limited to a paramedic, many times with little support in terms of specialist input or equipment to deal with victims of serious trauma. Injuries that might normally be considered relatively low risk in urban areas within the developed world may rapidly become life threatening in the absence of adequate medical facilities and expertise.

A successful medical evacuation ends when the casualty steps through the door of his or her home and not when the aircraft takes off or the ambulance departs the location of the accident. Achieving this goal involves several different teams of people from a variety of disciplines along the route who need to operate as part of a cohesive team if the evacuation and subsequent treatment of the casualty are to have a successful outcome.

Of critical importance is the need to implement a comprehensive system of care that will ensure as far as possible that a medical evacuation is properly handled at every stage in the process. This paper describes the components of such a system and how it was implemented for a remote location in the Sahara desert.
Assessment of Produced Water Injection Performance during Waterflooding of a North Sea Field Using Data-Mining Techniques
Authors: Zaki K. S. , Abou-Sayed A. S. , Roehl E. A.
Published: December 2007

This paper presents a study in which injector performance is evaluated during water flooding operations in a North-Sea Field. It is well known that water quality and well conditions strongly affect injection performance. Poor water quality leads to plugging and bacterial growth which results in a loss of permeability and injectivity decline. The effect of poor water quality can be mitigated through the treatment and removal of harmful solids, dissolved oxygen (DO) and bisulfites (BI). Long-term remideation can be achieved through various stimulation techniques. However, technology limits and frequent treatment plant upsets can negate the effects of these mitigations and frequent stimulations would result in significant costs.

Optimization of injection operations depends on the selection of the proper strategy and answering questions such as "Which water contaminants have the biggest impact?" and "How much would stimulation improve injectivity?" Surprisingly, reliable answers are difficult to obtain because interactions among injection variables are obscured by highly- complex, process dynamics (time-dependencies). In this study, data mining techniques were applied in order to understand factors that affect field injection performance. The study used 11 years of injection and water quality data from 14 wells in two different blocks. Dynamic models of well behavior were synthesized using a combination of "artificial neural networks" (ANN), a machine learning technique from the field of Artificial Intelligence and "multivariate state space reconstruction" from the Chaos Theory.

Sensitivity analysis performed using the ANNs revealed the relative impacts of each variable on injector performance. Despite different histories for each well, the models were relatively uniform in quantifying the relationships between the variables. Findings included - a different response to acidizing in each block; delayed cumulative formation damage from each variable of 1-3 months; the impact of DO was more than twice that of particulate matter (PM) and BI; and clorides (CL) had only a small affect on suppressing bioactivity. The uniformity and clarity of these results reduce uncertainties and provide operators with detailed knowledge to help optimize their injection designs.
Effect of Well Placement on Production and Frac Design in a Mature Tight Gas Field
Authors: Cipolla C. , Peterman F. , Creegan T. , McCarley D. , Nevels H.
Published: December 2007

This paper details the application of microseismic fracture mapping in conjunction with in-depth treatment evaluation to improve infill well placement and understand fracture treatment behavior and well performance. Microseismic mapping was performed on two nearby infill wells, with a total of total of nine treatment stages mapped. The wells were Canyon sand completions located in the Sonora Field, Sutton County, Texas.

The microseismic mapping results for Well A showed long fractures, averaging 845 ft, while the Well B mapping showed short fractures, averaging only 360 ft. Fracture heights varied considerably, ranging from 60 ft to 415 ft, with variations similar in both wells. In some cases fracture height growth from a lower stage would extend into the upper stage sand(s), indicating possible opportunities to optimize the number of stages pumped and perforation placement. The fracture azimuth in Well A exhibited a definite N40°E trend, while the results for Well B indicated very complex fracture growth with fracture propagation in more than one direction. The treatment behavior for these two wells was also very different, with Well A exhibiting lower instantaneous shut-in pressures (ISIPs) at the end of the jobs compared to Well B.

Gas production from Well A was significantly better than Well B. After reviewing the placement of Well A & B in conjunction with the likely fracture azimuth and subsequent elliptical production patterns for existing (older) offset wells, it became clear that offset well production in the vicinity of Well B had influenced fracture growth due to lower pore pressure and local changes in the stress field – resulting in complex fracture growth. In contrast to Well B, Well A was located in an area that was not significantly influenced by offset well production.
Treatment of Produced Water from Polymer Flooding Process Using a New Type of Air Sparged Hydrocyclone
Authors: Liu S. , Zhao X. , Dong X. , Miao B. , Du W.
Published: December 2007

Produced water from polymer flooding(polymer produced water) was difficult to be treated by conventional two-stage settling process. A new type of double-cone air sparged hydrocyclone (DcASH) was designed to treat produced water from polymer flooding. The experimental results showed that DcASH had a high capacity, and it was a very promising device for treatment of produced water from polymer flooding.
Short-Term Numerical Simulation of Geological Sequestration of CO2 in the Barrow Sub-Basin, West Australia
Authors: Yang Q. , Dong Y. , Zhou F.
Published: December 2007

It is important to predict the economical feasibility of geological sequestration of CO2. This paper applies reservoir simulation to model the characteristics of CO2 injection in the specific injection site location.It could provide input to the economic evaluations by defining Bottom Hole Pressure and injection relationships. Selecting an appropriate grid system was particularly discussed in this study. The flexible corner point grid system and grid refinement technology were proven to be suitable for the simulation of CO2 geological sequestration. By this approach, we finally obtained the ultimate capacity of reservoir to store CO2, and further produced data about different possible injection scenarios needed for economic modeling. It was concluded that the geological structure and direction of CO2 migration were two important factors in the selection of the optimum well pattern. The results showed that using one well can satisfy the injection requirement, and also CO2 geological sequestration in the Barrow Sub-basin is feasible.
Reducing the Footprint of 3D Seismic in the Tropical Rainforest of Ecuador
Authors: Thurber M. , Westlund D. , Benalcazar F. L.
Published: December 2007

Multiple seismic exploration programs have been conducted in the Ecuadorian Amazon since the 1970s without reusing previously cleared areas for heliports and camps, resulting in unnecessary cumulative deforestation impacts. Walsh Environmental Scientists and Engineers (WALSH) and EnCana have developed a remote sensing technique to eliminate these redundant impacts by accurately identifying historic heliports and camps in mature tropical rainforest for reuse in a 3D seismic exploration program.
Evolution of Frac-Pack Design, Modeling and Execution in the Ceiba Field, Equatorial Guinea
Authors: Cipolla C. L. , Shucart J. K. , Lafitte J. R.
Published: December 2007

Proposal

The paper details a study of fifteen frac-packs in twelve wells in the Ceiba Field, offshore Equatorial Guinea. Initial frac-packs were very unpredictable, experiencing numerous early wellbore screenouts and unpredictable tip screenout (TSO) behavior, placing proppant volumes of 10 to 160 klb with TSO net pressure increases ranging from 100 to 1,500 psi. The goals of this study were to: (1) develop a fracture modeling approach that would more reliably predict TSO behavior using mini-frac data, (2) develop reliable mini-frac analysis procedures and (3) determine the primary cause(s) of the early wellbore screenouts. The study resulted in improved designs, better execution procedures, more predictable TSO behavior and a reduction in early screenouts.

After reliable analysis procedures were developed, it was clear that mini-frac fluid efficiency and net pressure varied dramatically in the Ceiba frac-packs, with efficiencies ranging from less than 5% to over 30% and net pressure ranging from 170 to 900 psi. After reviewing rock mechanical data and evaluating various fracture modeling approaches, the variations in net pressure were attributed to complex fracture growth due to high wellbore deviation and long perforated intervals (as opposed to differences in modulus). The combination of consistent mini-frac analysis procedures and a fracture modeling approach that included fracture complexity resulted in a much more reliable prediction of TSO behavior.
Deconvolution of Variable-Rate Reservoir Performance Data Using B-Splines
Authors: Ilk D. , Valko P. P. , Blasingame T. A.
Published: December 2007

This work presents the development, validation and application of a novel deconvolution method based on B-splines for analyzing variable-rate reservoir performance data. Variable-rate deconvolution is a mathematically unstable problem which has been under investigation by many researchers over the last 35 years. We believe that this work is an important addition to existing well test/production data analysis methods where few deconvolution methods are practically applicable.

We use B-splines for representing the derivative of unknown unit-rate drawdown pressure and numerical inversion of the Laplace transform is utilized in our formulation. When significant errors and inconsistencies are present in the data functions, the direct and indirect regularization methods (i.e., mathematical "uniformity" processes) are used. We provide examples of under and over-regularization, and we discuss procedures for ensuring proper regularization.

We validate our method with synthetic examples generated with and without errors (for this work we provide cases with 10 percent error, but we have considered cases with as high as 40 percent error). Upon validation, we then demonstrate our deconvolution method using a variety of field cases — including traditional well tests, permanent downhole gauge data as well as production data. Our work suggests that the new deconvolution method has broad applicability in variable rate/pressure problems — and can be implemented in typical well test and production data analysis applications.

Objectives

The following objectives are proposed for this work: To develop and validate a new deconvolution method based on B-spline representations of the derivative of unknown constant rate drawdown pressure response (i.e., the undistorted pressure response).To create a practical and robust deconvolution tool that can tolerate relatively large (random) errors in the input rate and pressure functions. The proposed process should also be capable of tolerating small systematic errors in the input functions (via calibrated regularization).To apply this new method to traditional variable-rate/ pressure problems, such as wellbore storage distortion, long-term production data, permanent downhole (pressure) gauge data, and well tests having multiple flow sequences.
The Use of Swell Packers as a Replacement and Alternative to Cementing
Authors: Kennedy G. , Lawless A. , Shaikh K. , Alabi T.
Published: December 2007

Today the cement job is the most common technique used to achieve the critical hydraulic seal between casing and formation to isolate individual zones and prevent annular flow. As such, it is often considered one of the most important operations during construction of the well. However as an isolation mechanism, it can fail, and may not provide the down hole zonal isolation needed during the life of the well.

Annular packers based on the swelling of rubber in hydrocarbons are being used by different operators to replace cementing and provide the critical zonal isolation required down hole. The swell packer is able to overcome many of the shortcomings associated with conventional cement operations, and provide superior zonal isolation in both simple and complex well environments. Using swell packers also simplifies and reduces the risk of the well construction process and provides significant cost savings due to reductions in rig time and materials.

This paper focuses on the application of swell packers to provide an effective hydraulic seal between the formation and the casing as an alternative to cementing and perforating. Specific case histories from Nigeria, Malaysia and the North Sea are used to illustrate the success and application of this innovative technology.
Food for Thought—A Strategy for Improving Food Hygiene and Safety in Catering Operations
Authors: Phillips B. , Minshell C.
Published: December 2007

Providing safe and nutritious food and water to employees in remote areas is not without challenge, particularly in a large project where the number of employees is increasing rapidly and the caterer is expected to cope. The control of catering contracts can become more fragmented with the risk of illness from food and water hazards exponentially increased.

To manage this, a ‘food safety specialist’ was brought in to join the regional health team to identify essential issues and produce a methodology and strategy based on minimum acceptable standards in food hygiene and catering management.

A 3 stage process was designed: Introducing ‘effective’ hygiene inspections and action trackingEquipment and infrastructure improvementsFood hygiene training and awareness for all levels, accredited by a professional body in the UK.
Laboratory and Simulation Investigation of Enhanced Coalbed Methane Recovery by Gas Injection
Authors: Tang G.-Q. , Jessen K. , Kovscek A. R.
Published: December 2007

Methane/carbon dioxide/nitrogen flow and adsorption behavior within coal is investigated from a laboratory and simulation perspective. The samples are from a coalbed in the Powder River Basin, WY. They are characterized by methane, carbon dioxide, and nitrogen sorption isotherms as well as porosity and permeability measurements. This coal adsorbs almost three times as much carbon dioxide as methane and exhibits significant hysteresis among adsorption and desorption isotherms that are characterized as Langmuir-like. Displacement experiments were conducted with pure nitrogen, pure carbon dioxide, and various mixtures. Recovery factors are greater than 94% of the OGIP. Most interestingly, the coal exhibited ability to separate nitrogen from carbon dioxide due to the preferential strong adsorption of carbon dioxide. Injection of a mixture rich in carbon dioxide gives slower initial recovery, increases breakthrough time, and decreases the volume of gas needed to sweepout the coalbed. Injection gas rich in nitrogen leads to relatively fast recovery of methane, earlier breakthrough, and a significant fraction of nitrogen in the produced gas at short times.

A one-dimensional, two-phase (gas and solid) model was employed to rationalize and explain the experimental data and trends. Reproduction of binary behavior is characterized as excellent, whereas the dynamics of ternary systems are predicted with less accuracy. For these coals, the most sensitive simulation input were the adsorption-desorption isotherms, including scanning loops. Additionally, the coal exhibited a two porosity matrix that was incorporated numerically.
The Effects of Displacement Rate and Wettability on Imbibition Relative Permeabilities
Authors: Nguyen V. H. , Sheppard A. P. , Knackstedt M. A. , Pinczewski W. V.
Published: December 2007

A new dynamic network model is used to investigate the effects of displacement rate and wettability on imbibition relative permeability. The network geometry and topology is representative of a Berea-type sandstone. In contrast to existing quasi-static network models where snap-off, the major pore-scale trapping mechanism in imbibition, is suppressed by contact angle alone, the dynamic model introduces displacement rate as an additional snap-off inhibiting mechanism. The network model is used to analyse the complex rate dependence of relative permeability and residual saturation displayed by laboratory measured data reported in the literature.
Value Creation with a Novel, Multiphase Flow Additive
Authors: Misman R. B. , Aggrey G. H. , Davies D. R. , Fortuin H.
Published: December 2007

A main challenge faced by the Oil Industry is to develop marginal discoveries and to maintain production from existing, depleting fields against a background of unstable oil price and increasing costs. Operators seek new, cost effective ways to increase their discovery's commercial viability and to meet the growing world energy demand. Multiphase field development is one such tool to reduce costs. Here liquid and gas are transported together over long distances in a multiphase pipeline. Multiphase technology is becoming accepted by the industry - gaining popularity as field experience increases and the accuracy of performance prediction tools proven.

Field experience has shown that the higher-pressure drops and the formation of large, liquid slugs are two of the drawbacks associated with multiphase rather than the traditional, single phase pipelines operations. Both of these negative, multiphase flow effects can be mitigated by use of a new class of production chemical that is effective in both reducing the flowing pressure drop and influencing slug formation. This new class of chemicals is effective in two phase flow – unlike the well established "Friction Reducers" which are widely used in (single phase) water and oil flow.

The value creation from the application of this chemical has been quantified for a range of model reservoirs located onshore, offshore and in deepwater. A multi-well field & export simulation showed that up to 10% acceleration for oil and gas condensate production could be achieved by the use of the new chemical to the multiphase flow. Additional recoveries varied between 0 to 10%. Other condensates recovery scenarios gave up to 25 % increase in production rates for depleted reservoir. Even better results were obtained in condensate fields with inadequate pressure/aquifer support.

Economic analysis showed that production acceleration without recovery increase improved the economic value (pre-Tax NPV) of multiphase projects by 5%-15%. The additional value created by a concurrent additional recovery gave a pre- tax NPV increase of 13-25%

Multiphase technology with Floostar injection is an important enabler in the development of marginal fields and deepwater prospects, improving company's reserve portfolio.

A full economic analysis of these Field Development scenarios will also be reported
Development and Field Testing of a Unique High-Temperature/High-Pressure (HTHP) Oil-Based Drilling Fluid With Minimum Rheology and Maximum SAG Stability
Authors: Taugbøl K. , Fimreite G. , Prebensen O. I. , Svanes K. , Omland T. H. , Svela P. E. , Breivik D. H.
Published: December 2007

When drilling wells in HTHP fields, the drilling fluid properties are of utmost importance. The difference between fracture and pore pressure, expressed as the hydraulic window, can be quite narrow. One of the remedies for making sure that one stays within this hydraulic window, is to design a drilling fluid with very low viscosity. This will reduce the Equivalent Circulating Density (ECD) effect from the fluid. While low- viscosity fluids have the ability to dramatically reduce frictional pressure loss compared to more viscous fluids, there is a limitation to the reduction in viscosity before conventional weight materials start to settle. In HTHP wells with extremely high pressures and temperatures, sag stability of the fluid is essential to ensure adequate well control.

This paper describes the development and application of a novel technology that has resulted in a ten-fold reduction in the particle size of the weighting agent. With this development, invert emulsion drilling fluids can be designed with reduced viscosity in combination with minimal settling potential of the weighting agent.

The paper further explains in detail the first field application of this specially treated micron-sized weighting agent used in a HTHP well. This successful field application has proven this technology to be a viable alternative to the use of high-density, high-cost brine-based drilling fluids.
Hole Cleaning and Pressure-Loss Prediction From a Bulk Transport Perspective
Authors: Datta B. K. , Ratnayake C. , Saasen A. , Omland T. H.
Published: December 2007

Hole cleaning is still among the most important problems to handle in drilling operations and one of the most studied phenomena within the petroleum industry. Insufficient hole cleansing can lead to stuck-pipe, excessive pump pressures and equivalent circulating density (ECD), pack-offs, lost circulation, etc. all of which again can lead to loss of sections or complete wells. Due to the number of parameters influencing the hole cleaning operation and the complex mechanisms involved, the phenomenon has not yet been fully understood.

The issue of transportation of cuttings along with drilling fluids is essentially a two-phase flow. Several other industries are dealing with similar issues when transporting solids using air (fluid) as the transporting medium. Although the transporting mediums are different, flow regimes and basic transporting mechanisms similar to hole cleaning can be observed also in pneumatic conveying of particulate materials. While horizontal and vertical pneumatic transport are quite often used, very rarely people try to use inclined pneumatic conveying for the very reason that it involves much higher pressure drop as compared to both horizontal & vertical conveying and is associated with the problems of particles dropping out of suspension unless a very high fluid velocity is used. Through an extensive laboratory study a simple model1,2,3 has been developed for pressure drop calculation in pneumatic conveying based on classical Darcy's equation with some modifications. The predicted pressure values match well with the test data.

This article has tried to look at the possibility of a unified approach for two-phase flow. An attempt has been made to relate the knowledge developed in the field of two-phase pneumatic conveying systems to the challenges associated with the hole cleaning mechanism. The paper also describes some of the work that has been performed for studying hole cleaning and the associated pressure loss prediction.
A Comparative Assessment of Options for Produced-Water Management in the North Sea
Authors: Ekins P. , Vanner R. , Firebrace J.
Published: December 2007

There is currently no evidence of harm to the marine environment from produced water, but a number of areas of uncertainty remain. Using a novel methodology to compare a number of different techniques of reducing produced water discharges, it is found that these techniques have significant environmental and financial implications. In the absence of evidence of actual environmental harm being caused by produced water, the current policy objective of achieving zero discharge of hazardous substances in produced water implies a relatively high social valuation of the reduction in environmental risk that this achieves.
Risk Minimisation by the Use of Failure Mode Analysis in the Qualification of New Technology
Authors: Hother J.
Published: December 2007

Industry has recently recognised the value of failure mode analysis, which is now being used on a rapidly expanding scale, to reduce the risk associated with applying new technology and increase the probability of success.

Early applications showed forcefully that some of the methods used in other industries, for which there are internationally accepted standards, are not directly usable in oil and gas projects. Significant effort has now been applied to correcting these shortcomings.

This paper explores the aspects in which traditional methods have been found to be inappropriate, and demonstrates current best practice, including a number of new developments, illustrated by examples from recent case studies on well completions, intelligent wells, permanent downhole gauges, expandables, and new sand control technologies.

Those new developments address key issues that have been recognised as result of recent project experience, namely — oHaving a good definition of functional requirements before embarking on failure mode analysis.oHandling the life-cycle phases (primarily installation and production / operation) in a coherent manner, especially where downhole equipment is concerned, because many failure modes impacting production and value/investment criteria originate during installation.oMaintaining sufficient traceability to route-map from critical risks to specific components or process steps, so that avoidance or remedial measures can be accurately targeted.oRelating consequences of failure to the true economics of the project in hand, representing the different life-cycle phases realistically.oProducing useful results beyond just identifying critical failure modes, namely key actions targeted at specific aspects of the design, QA/QC, test procedures and installation processes, thus becoming an integral art of a coherent qualification process.

These issues are important wherever the risk of applying new technology is high, which is true of most oil and gas E&P projects. The risks are higher still when projects have significant downhole complexity, because the downhole elements are subject to the worst operating conditions and may have the highest consequences of failure. It is important to understand the failure modes, in order to focus the testing for maximum effectiveness, and to feed back improvements into the design and into the application, to maximise reliability.

This work has been instrumental in developing the methods that are now being widely adopted in oil and gas projects because they satisfy the unique needs of this industry.