bluuebunny/crossref_metadata_2025 huggingface dataset:
Evaluation of Acid Treatment Results for Water Injection Wells in Saudi Arabia
Authors: Al-Harbi M. S. , Al-Dhafeeri A. M. , Al-Rufaie Y. A. , Mohammed S. K.
Published: December 2007

Several acid treatments were conducted in the Ghawar filed to increase the well injectivity and to support the reservoir pressure in this area. Vertical and horizontal wells with an open hole completion in a carbonate reservoir were selected to be a candidate for post acid treatments evaluation study. These wells were stimulated using hydrochloric and emulsified acid with foamed viscoelastic-based water. Viscoelastic-based water system was used to enhance the diversion mechanism and the lifting process for the spent acid following the treatment.

In this paper new correlations for acid treatment design were obtained from an extensive study of several case histories that can be used for optimizing future acid treatments design in the Ghawar field. This study was mainly utilized the results from the post acid treatment jobs in terms of HCl acid, emulsified acid and viscoelastic volume correlated with the well's injectivity.

Based on the study results, there is a strong relationship between the emulsified acid volumes with the injectivity index for the selected wells.
Effective Well and Reservoir Management Reverses Production Decline in a Major Brownfield in South Oman
Authors: Choudhuri Biswajit , Al-Qarshubi Ibrahim , Sadek Ehab , Bharti Sanjay , Mahrooqi Salim
Published: December 2007

A large brown-field in South Oman showed decline in production despite moderate level of in-fill drilling over the last few years. The field has four major reservoirs distributed across three stratigraphic horizons and contains moderate to highly viscous oil (60 to 400 cp). The reservoirs comprise unconsolidated fluvial, fluvial deltaic and glacial sandstones of Palaeozoic age. The geologically complex field due to large number of faults and fractures has been on production for more than 25 years and has been developed using vertical and horizontal wells during different phases of development. Water-flooding is in operation in two of the major reservoirs for more than 5 years. Well and Reservoir Management in this field poses a formidable challenge due to:

Significant well-stock (more than 450 wells) of different types (vertical, horizontal, multi-lateral) Problem associated with data acquisition as all the wells are completed with pumps (beam pump, progressive cavity pump and electrical submersible pump) and most of them are completed with some sand-control device Water-flood management under very adverse mobility conditions in presence of faults and fractures often resulting in premature breakthrough of injected water Logistical problems associated with large distance between the Well and Reservoir Management team at corporate office and the operational team at field location.

The case study presented in this paper describes how a sustained well and reservoir management strategy implemented across the entire value chain starting from the planning to operation stage in this field could not only arrest but literally reverse the field production decline trend using the existing well stock. The paper clearly illustrates that success of reservoir management rests not only on the application of right technology but more on close integration among various disciplines in a cohesive work environment.
Can the Existing F&G Detection System Provide Safe Guard Against All Possible Gas Releases? (Case Study)
Authors: Shabaka Ashraf E.
Published: December 2007

The Fire and Gas detection systems in many of the existing facilities were designed in a conventional method without software modeled design and therefore their performance are questionable. This is due to the fact that at the time when designed, the dispersion and fire were not yet widely implemented.

Since the major accidents are unlikely to occur and it is therefore uncommon to revisit and verify the adequacy of the design of these systems.

This paper discusses the importance of revisiting the design of the existing fire and gas detection systems and its rule in saving our facilities from major losses.
Clustering and Corridoring Project
Authors: Elabed Amjad , Remisio Luis , Katchi Khaliquzzaman , Rahim Ihtisham Ur
Published: December 2007

By late 90's, Abu Dhabi Company for Onshore Oil Operations (ADCO) started facing increasing surface congestion and related potential operating hazards caused by haphazard laying of new surface assets/facilities in ADCO concession areas due to the implementation of aggressive field development plans. ADCO Management realized very early the need to reduce congestion and reduce the risk to the equipment and personnel while coping with the increased number of surface equipment as business needs expanded. As a result, the Clustering and Corridoring (C&C) Project was launched in 2003 and was divided into three studies phases. Phase I and II studies defined the optimum configuration of the facilities to control congestion and reduce the surface facilities footprint. The studies outcome was the development of four main design concepts:

Exclusion Zones, Well Pairing, Corridors Design, and Radial Corridors Layout.

Phase III studies resulted in the re-defining of Production Pad concept in order to meet the long term field development requirements. To date a total of 81 flowlines have been laid in the corridors in all ADCOs' major fields and a total of 24 wells were clustered since May 2005 in line with the Clustering and Corridoring Project guidelines.
Applications of Acoustic Liquid Level Measurements in Gas Wells
Authors: McCoy J. N. , Rowlan O. L. , Becker D. , Podio A. L.
Published: December 2007

Optimum production of gas wells requires static and flowing pressure surveys to detect excessive liquid loading. Wireline pressure surveys have been customary in spite of their cost and potential safety risks. Developments in digital acoustic fluid level technology have resulted in being able to undertake, not only static bottom hole pressure calculations from fluid level measurements, but also to extend this technology to flowing pressure surveys in gas wells. The new procedure involves monitoring fluid level and pressure in the tubing during a short-term test sequence. The procedure is inexpensive and non-intrusive. Tests clearly show the redistribution of flowing gas and liquid and allow the construction of the corresponding tubing pressure traverse and the determination of the flowing gas/liquid ratio, liquid fallback volume and flowing BHP. Examples of tests performed in operating gas wells that are flowing above or below critical flow rates are discussed in detail.
Integrated Interpretation of Production Data and Reservoir Fracturing Treatment Data Aimed to Improve Performance of Well Stimulation Operations by the Example of Vasyuganskaya Formation
Authors: Beryuschev S. , Bebee R. , Shaoul J. , Davidson B. , Vasiljeva V.
Published: December 2007

Hydraulic fracturing (HF) became one of the main techniques for production enhancement in the Pokamasovskoye oilfield.

While analysing production data (Qliq, water cut, BHP) and fracturing data (net pressure), similar trends became apparent, relating to the proportion of oil and water production after fracture treatments. In particular, after analysing several wells we were able to find similar explanations for production profiles before and after treatments.

Correctly determining initial conditions was the basis for developing this integrated approach. In particular, the following parameters: formation pressure (including measurements from observation wells); long term pre-fracture production data; permeability calculated with petrophysical relationship "core-SP"; identifying lithology types from openhole & cased hole logging data for sandstone, shaly-sandstone, shale, tight rock; rock-mechanics properties measured on cores (E, v); fluid rheology (k', n', viscosity); water source (pH, Fe, Cl); and "StimLab" proppant specifications (including proppant damage factor for reservoir conditions).
P-Wave Azimuthal AVO in a Carbonate Reservoir: An Integrated Seismic Anisotropy Study
Authors: Johns M. K. , Wang D. Y. , Lu C. P. , Sun S. Z. , Xu S. , Zhou Da
Published: December 2007

Seismic anisotropy is sensitive to intensity and orientation of fractures aligned by tectonic or local stress field. Azimuthal anisotropy of amplitude versus offset (AzAVO) is one common measure of seismic anisotropy for fracture detection. For this study, we calculated P-wave AzAVO attributes for a lower Cretaceous limestone reservoir in east Texas. Our study tests AzAVO inversion for the relatively low-fold, fair data quality typical of some land surveys. We developed a workflow to integrate the AzAVO inversion with rock physics, forward seismic modeling, seismic-scale fault interpretation, image logs, and core.

Our AzAVO inversion method was based on Rüger's equation, which describes the observed reflectivity (R) as a function of normal incidence amplitude (A0), AVO slope (B0), anisotropy magnitude (B1), anisotropy orientation (ϕ0), and noise (ni):

R ( θ i   ,     ϕ i ) ∼ A 0 + [ B 0 + B 1 cos 2 ( ϕ i − ϕ 0 ) ] sin 2 θ i + n i

Inversion of Rüger's equation yielded four attribute volumes (corresponding to A0, B0, B1, and ϕ0). Additionally, we proposed a additional data quality parameter which describes the relative amount of the total reflection energy predicted by the model. Pre-inversion processing carefully preserved signal via random noise attenuation, super-binning, bandwidth balancing, and phase alignment.

In general, AzAVO inversion displayed geologically interpretable, high anisotropy anomalies. Noise, however, limited our confidence for quantitative fracture prediction. On the flanks of the anticline, data quality was high (greater than 50% fit). Here the magnitude of the anisotropy (B1) volume showed strong lineations parallel to NE-SW trending faults. Over the crest of the anticline, the inversion quality was degraded by an overburden effect, coincident with poor data quality fit (less than 50%). AzAVO orientation maps were noisy and in some places obscured by an acquisition footprint. Locally, however, AzAVO orientations were parallel to ENE fracture orientations from core, maximum horizontal stress from image logs, and fast-velocity direction from a dipole sonic log.
Application of Model-Based Uncertainty Analysis
Authors: Lee Li-Bong W. , Krum Glenn L. , Yao Tingting , Wattenbarger Robert C. , Landis Lester H.
Published: December 2007

Model-Based Uncertainty Analysis (MBUA) is a method to evaluate reservoir performance using multiple 3D models. Experimental Design techniques are used to determine which 3D models are built (unique geologic models which are then simulated) based on the number of identified uncertain factors. This method determines main factor effects and factor interaction effects and results in a multivariable response surface for each desired outcome (i.e., EUR, STOOIP) that can be used for Monte Carlo simulations. The entire MBUA process results in tornado plots, exceedence curves and a method to build representative models.

A key strength of the MBUA process is the ability to quantify the uncertainty of dynamic responses such as water rate, production at early times and plateau length. These responses provide project teams a greater understanding of how their subsurface uncertainties impact field performance and can help guide additional technical work, development planning decisions and representative model building.

We have applied either a full or partial MBUA process to several fields for the purpose of identifying key technical uncertainties and improving the development plan across likely outcomes. Once an initial base case model has been constructed, the Reservoir Evaluation Time Reduction (RETR) work process is used to rapidly and efficiently build subsequent geologic and flow simulation models (totaling 16-54 models). Production data have been incorporated through either history-matching the initial base case or examining Monte Carlo simulation results for potential trends.

The uncertainty analysis provides a streamlined process to examine potential uncertainty factors and allows a project to make informed decisions regarding future technical work or potential mitigation plans.
Petrophysical Evaluation of the Igneous Gas-Bearing Reservoir Fractured—A Case Study at Xujiaweizi Area Outside Daqing Oilfield, China
Authors: Huang Wei , Zhang Yujin , Hu Yingjie , Liu Chuanping , Yin Changhai , Bian Yingshi , Zhang Fugong , Kong LIngfu , Li Tiejun
Published: December 2007

The igneous formation fractured; located at the YC1 and YC3 stratigraphic intervals at Xujiaweizi area outside Daqing oil field, China, had preliminarily shown a huge potential gas resource. That formation is the major gas exploration & development target in future, and a main provider for the gas reserve estimate and gas production. The igneous's low porosity made the resisitivity readings consistently high and detailed information about the formation productivity was difficult to obtain. As the results, the parameters, which used to estimate the gas reserves, were not completely determined by using of the conventional petrophysical methods on the openhole logging data. In order to provide the accurately gas reverse estimate and reservoir characterization in this area, the detailed petrophysical evaluation must be carried out based on the wireline log, core, gas chromatograph, well testing and producing data. This paper presents the case study on the petrophysical evaluation of the igneous gas-bearing reservoir fractured based on the data from 15 wells in which 3 wells were cored and 11 intervals in 4 wells were tested. The major contents are as follows, geological and logging features of the igneous formation, lithology identification of the igneous formation, determination and study of the petrophysical parameter (reservoir height models), identification of gas reservoir and determination of net pay and reserve parameter.
New Design Models and Materials Provide Engineered Solutions to Lost Circulation
Authors: Whitfill Donald L. , Jamison Dale E. , Wang Max , Thaemlitz Carl
Published: December 2007

The prevention and remediation of lost circulation during well construction employs engineered solutions that require a menu of services and tools to support the planning and application stages. Specialty software is used during the planning stage leading to the application of unique products and systems during the delivery stage. A feasibility study by technology specialists may include a wide range of tools during the planning stage to support data acquisition, modeling and design of the application stage. Planning services include hydraulics and fracture characterization modeling to assess expected Equivalent Circulating Densities (ECD) and their effect on potential lost circulation intervals. The fracture characterization modeling for borehole stress treatments uses a module that calculates both the expected fracture width and the particle size distribution required to plug the induced fracture and prevent propagation. The effect of these additions on the rheology of a non-aqueous drilling fluid can then be determined by the use of a new predictive rheology model. Application services may include real-time data acquisition to support delivery of specialized lost circulation materials and systems in either a preventive (pretreatment and/or borehole stress treatments to strengthen the wellbore) or corrective mode (mitigating lost circulation and, where possible, providing additional wellbore strength).
Well-Collision Risk in Congested Environments
Authors: Poedjono B. , Akinniranye G. , Conran G. , Spidle K. , San Antonio T.
Published: December 2007

Well-collision avoidance has gained greater importance as fields become more crowded and well paths increasingly complex. The safety and financial implications of shutting in production wells on platforms or repairing damaged wells have established a need for the industry to evaluate the potential for collision with a producing well.

This paper will cover three main topics related to minimizing the risk of well collisions:

Evaluating the risk Managing the risk Demonstrating the results of the new risk-minimization process

The paper will detail the processes of gathering appropriate data such as completion type, offset surveys, well pressures, casing depths, reservoir fluids and mud densities. Each well and field poses different challenges; not all data is available and wells can vary from simple vertical land wells to crowded offshore and fishbone multilateral designs.

The well position uncertainties are determined by using survey error models from the Industry Steering Committee on Wellbore Survey Accuracy. This method was chosen because it is an industry-recognized standard of defining the magnitude of survey uncertainty.

Recommendations for minimizing risk are based on the status and conditions of the adjacent wells and the nature and severity of the risks associated with a collision. These recommendations are formulated to minimize the risk while ensuring that production is disturbed as little as possible.
Production Tubing String Design for Optimum Gas Recovery
Authors: Poe B. D.
Published: December 2007

This paper presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells that produce free liquids in conjunction with the gas. Particularly important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required to continuously transport and unload liquids from the well. Sub-critical velocities are often encountered in low productivity gas wells that produce liquids, whether the wellbore liquids are produced directly from the formation and/or condensed from the gas in the wellbore. The produced liquids considered in the analysis can be water and/or liquid hydrocarbons.

This paper presents an optimization technique for determining the most efficient production tubing string setting depth design that will keep the wellbore continuously unloaded of produced liquids, yet result in the maximum gas recovery possible under those conditions. The optimization can be performed for a single completion operation during the productive life of the well, or for a series of periodic well interventions during the productive life of the well for which the tubing string setting depths are selected.

The wellbore liquid-loading mechanism in a sub-critical velocity production system has been considered in the analysis using a mechanistic wellbore outflow model. A commingled reservoir inflow performance model was utilized in the analysis to evaluate the fluid inflow of multilayer gas reservoirs that may produce liquids in conjunction with the gas.
Reliable and Effective Downhole Cleaning System for Debris and Junk Removal
Authors: Haughton D. B. , Connell P.
Published: December 2007

Wellbore debris is responsible for many of the problems and much of the extra costs associated with producing wells, especially in extreme water depths and highly deviated holes. Even a small piece of debris at the right place at the wrong time can jeopardize well production. For this reason, debris management has become a chief concern for oil and gas producers. Considering rig rates and completion equipment costs, debris removal is moving into the realm of risk management.

A clean wellbore is not only a prerequisite for trouble-free well testing and completion; it also helps ensure optimum production for the life of the well. Debris left in the wellbore can ruin a complex, multi-million dollar completion; it can prevent a completion from reaching total depth. And chances are, it will never reach an optimum production level.

These issues are pushing the industry to create reliable, efficient systems for quickly ridding wellbores of harmful debris and larger pieces of junk. This paper describes a vectored annular cleaning system (VACS) that can be used alone or in conjunction with any of an assortment of improved casing scrapers, brush tools, downhole magnet subs, downhole filter tools and junk catchers to optimize the efficiencies and economics of debris removal and save trips.

This paper will focus on the use of the vectored annular cleaning system to collect and remove debris from areas of the wellbore that traditionally are problematic; i.e., above liner tops, where casing size changes, areas with a loss of annular velocity, and wells with little to no circulation. Case histories from the Gulf of Mexico, North Sea and other areas of the world will demonstrate how this technology has reduced problems of debris removal while saving rig time by eliminating trips.
Block to Block Interaction Effect in Naturally Fractured Reservoirs
Authors: Shariat A. , Behbahaninia A. R. , Beigy M.
Published: December 2007

Initially, gravity drainage mechanism in naturally fractured reservoirs was modeled and validated by solving the available analytical equations (e.g. Firoozabadi and Hauge method in 1990). Block to block interaction effect has been included in this model. Then the effects of different parameters on recovery process were investigated and compared with the production mechanism of different models, such as, dual porosity, dual permeability. This work determined that the most effective parameters on recovery process are block height and matrix permeability. Also in the case of capillary continuity between the blocks, vertical fracture permeability has no effect on recovery process. The main conclusion drawn from this work is that reinfiltration causes a reduction in the production rate; however, it has no effect on ultimate recovery. Also it was concluded that trickled oil from blocks above always prefers to reinfiltrate into the matrix blocks below rather than flowing through the fractures. The following limitations and assumptions apply: 1-D flow.System pressure is constant.Fluid viscosities are constant.Fluids are incompressible.Model is valid only for two phase oil/gas system in the presence of immobile water.
Wellsite Permit to Work System for Onshore Australia
Authors: Gouldie T.
Published: December 2007

The Wellsite Permit to Work System is a universal work planning and scheduling system used by most onshore drilling and well servicing operations onshore Australia to assist in performing work safely.

The Wellsite Permit to Work System is part of an overall safety management system providing a means of improving communication, specifying and implementing appropriate work precautions, setting ongoing conditions under which work should be carried out, monitoring of a worksite for health and safety issues while work is being carried out, and inspection of sites following completed work to ensure it is safe to resume other operations.

Other features of the System include:

Permit types are specifically focused on wellsite, not plant, activities Only one permit form is used for all permit types Seven kinds of permits, including Working at Heights, Pressure Systems, and Explosives/ Radioactive System is applicable to both rig and non-rig work Self contained system, easily able to be transferable to work in yards, workshops and for most non-wellsite work System users need to be trained in only one system, with training certification transferable from wellsite to wellsite, regardless of the rig contractor or operating company

By carrying out the necessary precautionary steps and by following the ongoing work conditions as designated on a permit, wellsite workers greatly improve the co-ordination of wellsite activities and significantly enhance safe operations.

The Wellsite Permit Authority under the System is designated as the senior representative of the primary contractor on the location, such as a rig manager or toolpusher. Operating company personnel have the option to authorise permits on site, or can allow contractors to operate the System without intervention.

The Wellsite Permit to Work System has been in use in this format since 2001. An update to the System has recently been implemented by an industry Steering Committee to incorporate improvements to industry standards and capture learning's from the use of the first version.

This universal Wellsite Permit to Work System, used by the majority of onshore operating companies across all types of wellsite work, run by contractors without the need for operating company intervention and focused on wellsite work is said to be unique in the world.
Improved Window Cutting Efficiency Cuts Casing Exits Costs
Authors: Toulouse J. E.
Published: December 2007

Transferring PDC bit technology to milling equipment has resulted in a new casing exit technology that allows window milling and rathole drilling to be performed in one run to improve operational efficiency and cut drilling costs. The new technology expands the performance envelope for casing exits to significantly extend the number of wells that can be re-entered.

Using whipstocks and casing mills to exit existing wellbores has become commonplace. However, this operation is becoming more critical because extended ratholes are often required to accommodate long rotary steerable assemblies before new formation drilling can commence. Depending on window depth, the extra trip required to drill the rathole can take up to two days of rig time and significantly increase well costs.

To address these issues, a new-style formation mill has been developed that borrows from PDC design. to optimize cutting element efficiency and uses a special PDC compound to effectively cut both metal and formation. The mill is adaptable to many whipstock systems or can be run as standalone technology.

Since its introduction, the mill/bit has helped operators in various geographic regions reach new reserves economically. Performance has been closely monitored in applications ranging from through-tubing exits in 4.500 in. tubing to a 13.625 in. casing exit in deepwater salt and a 7 in. casing exit in 30,000 psi dolomite with chert nodules.

The tool has saved numerous trips on simple, hard-rock sidetracks as well as in deepwater plays using rotary steerable drilling systems.
Case Studies—Offshore Managed Pressure Drilling
Authors: Hannegan D.
Published: December 2007

Managed Pressure Drilling (MPD) technology has evolved on land drilling programs since the mid-sixties. However, it has been only fairly recently that the technology has found an important niche in the minds of offshore drilling decision-makers.

With most of the world's remaining prospects for oil and gas being economically un-drillable with conventional-wisdom casing set points and fluids programs, MPD is now being viewed as a technology which can render a significant increase in economic drill-ability by reducing excessive drilling-related costs typically associated with conventional offshore drilling.

This paper will define for the audience the two Categories (Reactive & Proactive) and the Variations of MPD that are being currently practiced or will be practiced in the near future in marine environments:

CBHP (Constant Bottomhole Pressure) PMCD (Pressurized Mud Cap Drilling) Dual Gradient (several methods) HSE (Returns Flow Control)

Case studies will be presented which speak to MPD applications from both fixed (Jackup, platform) rigs with surface BOP stacks…and from floating rigs (moored semi-submersibles and DP Drillships) with subsea and surface BOP's.

There will be an emphasis upon the "drilling trouble zones" benefits of MPD. Operator company objectives of practicing the variations of MPD will be detailed. Stances of various regulatory agencies will be briefly discussed.
Reservoir Management of West Salym Oil Field
Authors: Svirsky Dmitry , Hagelaars Ad , Zegwaard Joost , Mackay Howard
Published: December 2007

The West Salym oil field in West Siberia is a new development recently brought on stream in this mature petroleum basin. The field contains some two bln stb of oil in place. First oil was produced in 2004 and peak production is expected in 2012 at over 100,000 stb per day. Whilst the field is in an early development stage, it is crucial that reservoir management and data acquisition processes are put in place to allow efficient future field development and optimise oil recovery.

The paper focuses on four main aspects of the West Salym development: project management, well and reservoir surveillance, reservoir management and petroleum resources maturation. In the project management section the multi-disciplinary integrated team approach implemented in the sub-surface asset and field operations teams is highlighted. In combination with technology support from world-class technical expert groups, this allows effective implementation of surveillance and reservoir management activities in the field. In the reservoir surveillance section an overview of the field surveillance program is provided and experience of using surveillance technologies in West Siberia such as hi-end logging, wireline formation testing, specialised core analysis and geochemical fluid analysis is described. The reservoir management section concentrates on several technical aspects of West Salym development, such as well pattern and reservoir stress alignment, application of highly deviated wells as an alternative to hydraulic fracturing and management of water injection under fracturing conditions. The petroleum resources maturation section describes how the reservoir management activities result in the maturation of the field petroleum resources to reserves and improvement of oil recovery. Technology opportunities for innovative wells, permanent downhole metering and enhanced oil recovery processes are also reviewed.
Case Study: Subsea Intervention With a Jack-up Drilling Rig
Authors: Hargreaves B. , Mohr J. W. , Snow T. M. , Mamuko B. O.
Published: December 2007

ExxonMobil1 subsidiary Esso Australia Pty Ltd recently completed the first subsea intervention using a jack-up drill rig in Bass Strait, Australia. This case study provides an overview of the intervention and how the key challenges were overcome.

Prior to the intervention, the Seahorse-1 subsea well was producing 150 BOPD at 95% water cut from two stacked commingled zones. Reservoir analysis indicated that the more permeable lower zone dominated the commingled flow leaving unproduced reserves in the upper zone. The scope of the intervention was to isolate the lower zone so that the upper zone could be produced more effectively.

The nature of the intervention presented several key challenges: (i) there was uncertainty associated with availability and condition of the 16 year-old subsea equipment that had not been used since installation, (ii) potential to modify a jack-up rig was only identified four months prior to the planned departure date of the rig, (iii) positioning the rig around subsea equipment, and (iv) simultaneous operations (SIMOPS) were required to minimize the impact on production operations on the host gas platform.

The Seahorse-1 intervention was successfully completed by utilizing ExxonMobil's worldwide functional expertise in production, drilling and subsea operations. Upon completion of the intervention the well was brought online at 4000 BOPD.
Well Testing by Design: Transient Modelling for Predicting Behaviour in Extreme Wells
Authors: Teng D. , Maloney B. , Mantecon J. C.
Published: December 2007

Offshore rig rates are at an all time high and wells are becoming bigger and longer, in deeper waters and in more complex reservoirs. Well testing in this environment has become more challenging, where well clean-up and flow assurance issues such as slugging and hydrates can significantly extend the planned duration of well tests. The ability to predict and being prepared to deal with such problems by appropriate design of well test equipment can reduce operational risk, minimise safety hazards and environmental impact and potentially save millions of dollars in rig-time.

Traditional well flow software only models steady-state flow. Predicting the transient behaviour of wells, from the unloading of completion fluids until steady state flow conditions are reached, requires specialised software. Dynamic flow simulation software is a proven tool which has been applied for years by facilities engineers for pipeline and slug-catcher design, but its application for well testing is a new practice. Key outputs from dynamic well simulation include slug sizes and frequency, fluid composition and pressure-temperature trends at any time and at any point in the well. Such information enables optimum design so all parameters are within the equipment's allowable operating envelope at any time of the well test operation.

This paper describes how dynamic simulation, using the software package OLGA, was applied to a big-bore gas well with 9 5/8" production tubing. The dynamic simulation study: provided better understanding of well unloading behaviour at different flowrates (by using different choke sizes).assessed the effect of an emergency shut-down (ESD) during a well clean-up operation.defined the minimum flowrate required to cleanup the well (for sizing well testing equipment).

Results from the dynamic simulation indicated that a standard well test package may be adequate for cleaning up this big-bore gas well with 9 5/8" production tubing, though the equipment would be operated at or near its limits and would take quite some time for clean-up. A significantly faster clean-up could be achieved with a high rate well test package at additional cost.
Development Well and Execution Planning in a Complex Subsurface Environment— The Impact of Large and Small Scale Modelling on Well Deliverability
Authors: Philip G. , Twartz S. K. , DePledge J.
Published: December 2007

The Thylacine Gas Field is in the Otway Basin (Offshore SE Australia). The interplay of intra-field faulting and the layered geology mean that there is the potential for a high degree of compartmentalisation. A significant proportion of the reserves are thought to reside in the reservoirs of the Thylacine Sandstone Member, which are poor quality marine sands interbedded with successions of thinly bedded sand-shale and shale. Key to designing wells to achieve satisfactory deliverability was an understanding the distribution of net reservoir in the background of non-reservoir.

The Thylacine development required a low cost, highly efficient development concept to tap these reservoirs. The Thylacine Alpha platform provided a base for drilling of these horizontal wells. The horizontal wells required careful positioning and design to best exploit the resource, due to a mix of the complex structure within the field and significant reservoir quality and distribution uncertainty. To better place the wells, and enhance the outcome predictability for the wells, deterministic and probabilistic amplitude –versus-offset (AVO) inversions were carried out. Simple acoustic impedance models showed improved resolution over the PSDM data, and provided insight into reservoir architecture and geometry and hence confidence in our ability to predict reservoir occurrence for drilling across the field. In parallel, a review of the available core and log data from the exploration/appraisal wells supported construction of a geological model with built-in predictability. The combination of predictive geological model, aimed at improving sub-seismic resolution, and seismic inversion to identify trends in seismic scale reservoir geometry, proved invaluable in both the well planning and execution phases of the project.

This paper outlines the planning phase of the wells and influence of the geological model on resultant well designs and the preliminary outcomes of the execution phase.
Quality Control of Static Reservoir Models
Authors: Spilsbury-Schakel J. A.
Published: December 2007

In the current climate of large numbers of projects, ever shortening cycle times and increasing field complexity, there is a need for rigourous and agreed Quality Control (QC) guidelines for reviewing static reservoir models.

Within Woodside, the assurance process includes a combination of checklists, guidelines, and milestone reviews at predefined steps in the workflow, the latter being a combination of project framing, 10%, 75%, and fully integrated study reviews.

Although each field is different, and each study has its own objectives, common checkpoints are easily identified and can be grouped in general categories such as: study objectives; geological setting and correlation; input data; structural model; layering and log averaging; and facies and rock property modelling (Fig. 1). There are supplemented by the export to dynamic simulators, and comparisons between upscaled and finely gridded properties, including volumetrics. Most software packages provide some sort of audit trails whilst manipulating the data that makes up the static reservoir model.

A set of pointers with respect to general model QC are given, which are as handy as hints and tips for the beginner, and as reminders ("did you think about…") for the experienced static reservoir modeller.
Electrically Powered Drilling Equipment Used in Artic and Harsh Environments
Authors: Kverneland Hege
Published: December 2007

This paper focuses on the benefits with using electrically powered drilling equipment compared with hydraulically solutions in cold and harsh environments. Improved operational performance with higher availability of the equipment, easier installation and maintenance as well as health, safety and environmental (HSE) issues will be discussed. The paper will especially focus on permanent magnet motor (PM-motor) technology, which has recently been introduced in lifting applications and in larger drilling machinery. The possibilities when designing a PM-motor application is related to reduced size and optimized shape of equipment, as well as an enhanced safety aspect in lifting operations.
Calculation of Phase Behavior of Asphaltene Precipitation by Using a New EOS
Authors: Omidkhah M. R. , Nikookar M. , Pazuki G. R. , Sahranavard L. , Emadi M. A.
Published: December 2007

In this study, at first a new equation of state has been presented. Then vapor phase volume, liquid density, saturation pressure and enthalpy of 20 pure components are calculated by this EOS. The obtained results are compared to PR and M-PR equations of state and the accuracy of the new EOS has been approved. In the next step, the Flory-Huggins model has been modified and then the amount of asphaltene precipitation at different ratios of solvent are obtained using the new EOS and M-FH model. The estimated amounts of asphaltene precipitation by this model are compared to the experimental data. This comparison displays that the predicted amount of precipitation in crude oil by our model conform with the experimental data.
An Improved Method for Reserves Estimation
Authors: Thanh Truong Truong
Published: December 2007

Controlling potential risks in Petroleum Industry is one of the most difficult tasks for geologists, reservoir engineers and others. Evaluating oil and gas reserves becomes riskier and less accurate for fields which have complex geologic structure and high heterogeneity. In these cases, correlation relationship between dependent reservoir parameters will be represented better and more exactly with non-linear regression models.

The "box" method is introduced in this research as an improved technique in handling these more accurate non-linear regression models compared to conventional method – Spearman's rank order correlation method – which is available in many commercial Monte Carlo simulators. The conventional method is just correct in uniform and homogeneous reservoirs whereas the "box" method is better for complex and heterogeneous reservoirs.

To get the most accurate estimation of oil and gas reserves, a computer program using the above improved technique along with Monte Carlo simulation method was written. Some randomly generated data that were similar to data from a specific heterogeneous reservoir were also considered. And exhaustive simulation runs were performed to compare the results from written computer program to those from a commercial Monte Carlo simulation package. It was seen that their outputs were different due to different methods used.

Regarding such exactly estimated amount of oil and gas from written computer program, project designing team planned field development more accurately and efficiently. This very important factor led to a successful production project.
New Experience in Monofilament Fiber Tandem Sweeps Hole Cleaning Performance on Kharyaga Oilfield, Timan-Pechora Region of Russia
Authors: Bulgachev R. V. , Pouget P.
Published: December 2007

Drilling the 12 1/4" sections for the Kharyaga oilfield in the Timan-Pechora region of Russia has always been considerably complicated by wellbore instability and hole cleaning issues. These issues have been most serious when drilling through Triassic and Permian shales, sandstones, argillites and silts, followed by drilling Carboniferous limestones and dolomites. Unstable formations sloughing and packing off, wash outs and severe caving has resulted in many problems including drill pipe pack-offs, high torque and drag, the need for additional reaming operations, and difficulties in reaching bottom with casing.

Fluid treatments of swelling shales with chemical inhibitors helped considerably with shales hydration, but the problem of caving and packing off still persisted. High angles (up to 52.8°) and long section lengths (up to 2,707 m) aggravated the problems. The key remedy was determined to be effective hole cleaning. Cleaning efficiency of different types of sweeps was studied during drilling of 10 Kharyaga wells. Sweeps were pumped on a regular basis in drilling intervals of 100, 150, 200 and 300 meters, prior to pulling out of hole and when indications of packing off had been observed.

Pumped cleaning sweeps included high-viscosity or high-density single sweeps; tandem sweeps (low-viscosity following by high-viscosity or high-density sweeps); and sweeps with special additives (carbon-based LCM material or innovative monofilament fiber sweeping agent). Also, special attention was given to combined tandem sweeps, which are low-viscosity sweeps treated with a monofilament fiber sweeping agent followed by a high-density sweep (sometimes treated with carbon-based LCM material).

Investigation of different sweeps performance showed that the best hole cleaning results for Kharyaga field wells were achieved by circulating combined tandem sweeps, which are low-viscosity sweeps treated with a monofilament fiber sweeping agent followed by a treated or untreated high-density sweep.
Integrating Quantitative and Qualitative Rock Strength Data in Sanding Prediction Studies: An Application of the Schmidt Hammer Method
Authors: Taylor P. G. , Appleby R. R.
Published: December 2007

Despite continued advances in sand production prediction software, numerical modelling does not always agree with observed sandface behaviour once a well is flowing. Where core is available, computer models should be calibrated to laboratory determined rock strengths, measured on plugs cut from the core. The number of core plugs is often restricted due to time limitations and availability of good quality core. These may not be fully representative of the entire reservoir section due to complex variations in rock composition.

Sandstone failure and the onset of sand production can be more accurately predicted by integrating log derived rock strength, calibrated to rock mechanics laboratory test data, with petrographic observations made on the core; i.e. combining quantitative and qualitative methodologies. Such observations typically include mineralogy, rock texture, structure and reservoir quality. Laboratory numerical data are discrete, whereas log and observational data are continuous, and these do not always readily relate. This can make the integration of laboratory-to-field data a difficult process.

In an attempt to more closely relate quantitative and qualitative core data, a Schmidt impact testing hammer has been used to make hardness measurements along an entire core. The Schmidt hammer was originally designed for the non-destructive testing of concrete hardness in the civil engineering industry and was later adopted to estimate rock strength in mining, quarrying and tunnelling applications. The Schmidt hammer allows very rapid (and inexpensive) core testing, and has the added advantage of being non-destructive. Rock mechanics parameters can be determined in dense arrays that reflect the real inherent heterogeneity of the core.

Use of the Schmidt hammer has enabled extrapolation of laboratory determined rock strength across the entire core and has facilitated direct correlation of mineralogy and grain texture to sandstone failure and yield. Characterisation of overlying claystones has also provided essential data for the determination of stress shadowing effects. Further development and refinement of this technique should provide an additional useful tool in reservoir and overburden characterisation and predicting sand production.

The technique does not require specialist rock mechanics knowledge and can be applied at the well site or core viewing room. Useful data can be obtained from core material ranging from fresh state to old archived material. The speed and practicality of the Schmidt hammer as a rock strength characterisation tool is seen to have great potential.
Field Experiences With History Matching an Offshore Turbiditic Reservoir Using Inverse Modeling
Authors: Hohl D. , Jimenez E. A. , Datta-Gupta A.
Published: December 2007

Reconciling high-resolution geologic models with pressure and multiphase production history is one of the most time-consuming aspects of the workflow for geoscientists and engineers. Although significant advancements have been made in this area over the last decade, current industry practice largely involves iterative trial and error methods and often utilizes arbitrary permeability multipliers that lead to loss of geologic realism and consequently poor performance predictions.

In this paper, we demonstrate the application of an efficient inverse modeling scheme for history matching a waterflooded, structurally complex and faulted offshore turbiditic oil reservoir. The field has an estimated 500 MMSTB and is located in a prolific offshore hydrocarbon basin. Permeability and fault transmissibilities are the main uncertainties. More than 10 years of production data from up to 8 producing wells are available for history matching. Our approach combines the efficiency of the streamline-based sensitivity computations with the versatility and accuracy of finite difference models for matching the water cut at the producers.

Specifically, a finite-difference model is used for flow simulation and to generate velocity fields based on which we compute streamlines and sensitivities for updating reservoir permeability via fast inverse modeling. These sensitivities relate the reservoir properties to production data and can be obtained using a single flow simulation resulting in an efficient inverse algorithm for history matching. A unique aspect of the field study here is the novel approach used for streamline tracing and sensitivity calculations across faults and non-neighbor connections in the geologic models via local grid refinement.