bluuebunny/crossref_metadata_2025 huggingface dataset:
Magnetic Resonance Imaging of Methane—Carbon Dioxide Hydrate Reactions in Sandstone Pores
Authors: Graue A. , Kvamme B. , Baldwin B. A. , Stevens J. , Howard J. , Ersland G. , Husebø J. , Zornes D. R.
Published: December 2007

Formation and growth of methane hydrates in porous sandstone was monitored using Magnetic Resonance Imaging (MRI). A series of 3-D MRI images collected during these experiments illustrated patterns of hydrate growth. Calibrated MRI intensity changes that occured during the hydrate growth correlated with methane gas consumption and gave dynamic and quantitative in-situ information on hydrate formation rate and spatial distribution of the hydrate formed. Gas permeability was measured at various hydrate saturations and during hydrate growth. Experimentally it was verified that methane hydrate in porous sandstone spontaneously converted to CO2 hydrate when exposed to liquid CO2 at high pressure and low temperature. It has experimentally been determined that without heating, an exchange process between CO2 and methane occured allowing the injected CO2 to be stored as hydrate resulting in spontaneous production of methane, with no associated water production. The MRI images provided quantitative information on the methane production rates and amounts of methane released during the CH4-CO2 hydrate exchange reaction. Thermodynamic simulations based on Phase Field theory supported the measured results and predicted similar methane production rates observed in several reproduced experiments.
Experience from the Use of Automatic Well-Test Analysis
Authors: Oisen S. , Nordtvedt J. -E.
Published: December 2007

Today an increasing number of oil and gas wells are equipped with downhole and topside gauges for measurements of pressure and rates. These gauges are capable of providing data with a resolution up to every second. For each sensor, this can accumulate to millions of data points every year. Often only a small amount of these data are analyzed in order to retrieve the information they carry about well and reservoir conditions. This might be due to both time-consuming analysis and limited engineering time.

One analysis that can be performed on continuous data from permanent gauges is well test analysis after any well shut-in. In this paper, we will show that this analysis can be automated in order to minimize the engineering effort associated with performing it. This will provide the asset teams with additional information about well and reservoir conditions since today's workload for the engineers does not allow analysis of data from each well shut-in.

The analysis will be performed on real-time data for each detected arbitrary shut-in period, providing time series of the estimated parameters such as skin, permeability, reservoir pressure and drainage area. We show the benefit of linking the automated well test to an automated wavelet filter, where the filter purpose is outlier removal, denoising, compression and transient detection. This allows for developing a system whereby the data first is automatically filtered, compressed and made ready for analysis, and subsequently analyzed with a notification sent to the relevant engineers (also including a qualification on the success of the analysis). Hypothesis testing is finally performed to detect changes in data. If no changes are detected, average parameter values can be calculated. We show examples of such a completely automated well-test analyzer.
The Good, the Bad, and the Ugly of the Stage-Gate Project Management Process in the Oil and Gas Industry
Authors: Walkup G. W. , Ligon J. R.
Published: December 2007

Management teams across the globe have and will continue to bet on major capital projects to drive their companies' performance. Capital committed to these mega-projects has increased at a compounded average growth rate of over 12% over the last decade, and this trend is expected to continue over the next decade. To manage the shareholder value at risk in these projects, almost every major oil and gas company has invested heavily in a formal stage-gate project management process. Yet the performance of major projects has not appreciably improved, and significant project failures—both technical and economic—continue to occur.

We have investigated how the application of these state-of-the-art processes has gone astray in the oil and gas industry. We identify the key organizational and technical shortcomings that are diminishing project performance and suggest the top-ten actions management can take to gain significant competitive advantage.
Slimming the Wellbore Design Enhances Drilling Economics in Field Development
Authors: Tubbs D. , Wallace J.
Published: December 2007

Staying ahead of the curve sometimes requires reconsidering standard practices and vintage processes. One example that clearly illustrates this approach in the energy industry consists of planning solid expandable tubular technology into the casing design as a means to slim the wellbore. By incorporating the solid expandable tubular system at the beginning, the operator achieves a slimmer well profile while still maximizing hole size at total depth (TD), reduces drilling time to TD and reduces drilling costs.

An operator in Texas epitomizes the advantage of this approach by using the 6 x 7-5/8 in. expandable openhole liner in deep gas wells to proactively address zones prone to loss circulation. The operator maintained hole size and realized significant worth from this enabling technology. This proactive approach saved the operator over $1M per well. Applying this technology across field development projects leads to substantial savings.

For these wells, using solid expandable tubular systems to achieve a larger wellbore at TD resulted in the following features, advantages and benefits: Higher rate-of-penetration (ROP) in long intermediate casing section (36% enhancement)Overall drilling cost savings (15–20%) using slimmed wellbore vs. big bore pipe programImproved drilling performance and lower equivalent circulation density (ECD) below the solid expandable tubular system

This paper will detail how the planning and application of solid expandable tubular systems resulted in significant benefits. Drilling conditions, circumstances and environments will be discussed to illustrate how solid expandable tubular technology is conducive to efficient drilling operations. In addition, this paper will discuss the value realized from expandable applications and how these systems enhance the value of the customers' assets.
Benefits of the Novel Fiber-Laden Low-Viscosity Fluid System in Fracturing Low-Permeability Tight Gas Formations
Authors: Bulova M. , Nosova K. , Willberg D. , Lassek J.
Published: December 2007

Most of the low-permeability tight gas market that is treated by low-viscosity slickwater fracturing treatments results in ineffective propped fractures due to rapid proppant settling. Currently hybrid fracturing and ultra-lightweight proppants are employed for improving performance of slickwater treatments. The hybrid fracturing methodology uses a combination of linear and crosslinked gels to improve proppant placement. The disadvantages of existing lightweight proppants are their high cost and applicability only to reservoirs characterized by low closure stresses.

Novel fiber-laden low-viscosity fluid technology has been developed to improve proppant transport for hydraulic fracturing in low-temperature tight gas formations. Such a system creates a fiber-based network within the fracturing fluid that decouples proppant settling from fluid viscosity. This network entangles proppant, dramatically reduces proppant settling, and provides a mechanical means to transport and place the proppant at greater distances from the wellbore. An additional advantage of the new system lies in fiber degradability, which leads to a nondamaged fracture conductivity with time.

Fluid rheology of fiber-laden fluids was measured over a 150-230 °F temperature range under various fiber loadings. Studies showed that under bottomhole temperature and fluid pH fiber decompose and form a water-soluble species. During fiber degradation, the permeability of the fiber-laden system approaches the value of permeability for the baseline system without fiber. Compatibility study of the degradation byproducts with formation water showed no precipitate formation in high salinity environments.

The results demonstrate that the new fiber technology ensures uniform proppant placement within a long fracture, provides permeability equal to pure proppant pack values, and offers higher production rates in comparison with conventional fracturing treatments.
Accurate Volumetric-Flow-Rate- and Density-Based Water-Cut Measurement in Bubbly Liquid Hydrocarbon Flow
Authors: Volz R. , Gysling D. , Loose D. , Rawat A.
Published: December 2007

Oil and gas production is inherently multiphase. A significant cost of production is directed toward accurately measuring and allocating produced hydrocarbons. The presence of gas phase in liquid flow impairs accurate measurement, introducing errors in well and field production allocation. These errors distort the reservoir engineer production information and directly affect the fiscal allocation from multiple owners.

A SONAR-based system to measure the gas void fraction (GVF) next to turbine and Coriolis meters is proposed as a method to correct for gas bubbles. A test was conducted at Southwest Research Institute (SwRI) to validate this concept on realistic multiphase fluids. The SwRI test was designed to simulate separator liquid out-flow conditions and to assess the ability of GVF measurement to correct for the errors introduced by entrained gas in turbine and Coriolis meters.

The data show that both the turbine and Coriolis meters over-report the volumetric flow rate in proportion to the amount of entrained gas. Using a GVF measurement provides a simple correction to the primary measurement of both meter types to within ±1% of the reference liquid flow rate for 0–8% GVF. The Coriolis meter correctly measured the mixture (liquid + gas) density within ±1% of the reference, independent of entrained gas levels. The liquid density is required to determine water-cut and in this test it was calculated by correcting the measured mixture density for GVF. Using a simple GVF correction, the liquid density was reported to within ±1% for 0–10% GVF.

An accurate measure of liquid hydrocarbon volumetric flow rate and density independent of the amount of entrained gas can be achieved using turbine and Coriolis meters in conjunction with a SONAR-based GVF measurement. This capability enables improved reservoir management as well as increased separator design flexibility, reducing complexity, cost and weight.
The Origin and Resource Potential of Residual Oil Zones
Authors: Melzer L. Stephen , Koperna George J. , Kuuskraa Vello A.
Published: December 2007

Tectonics and active aquifers beneath oil-bearing reservoirs can be powerful forces in trapping large quantities of residual oil. In regions of the world where basin uplift (or subsidence) has created basinal tilt or where the oil columns are underlain by active aquifers, significant quantities of oil may have been swept from the original oil accumulation. In these situations, the once horizontal producing oil-water contact (OWC) transitions to a tilted interface across the field, creating a new and higher OWC. Below the new and now tilted OWC, there now exists a thick reservoir interval of immobile oil, called the residual oil zone (ROZ).

In the past, the ROZ was only water productive and therefore avoided. Today, with the advent of CO2 EOR and several demonstration projects, this oil zone (often quite comparable in residual oil saturation with the waterflood swept interval in the main pay zone) has been shown to be a technically viable target for additional oil recovery.

In the Permian Basin, OWC tilts have been mapped in many of the oil fields, particularly in the Permian age San Andres and Grayburg reservoirs. Examination of well logs clearly shows the presence of significant ROZs (often with 100's of feet in thickness) below the tilted producing OWC. Throughout the middle portion of the interval, the oil saturation is near residual oil saturation. The oil in place, due to ROZ thickness, is often on par with the original oil in place in the MPZ, representing a large, significant undeveloped oil resource.

This paper discusses the origin and resource potential of ROZs. The paper examines how: 1) regional or local basin tilt; 2) breached and reformed seals; and/or 3) altered hydrodynamic flow fields can form ROZs. Subsequently, the paper examines, using geologic and reservoir modeling, how key oil reservoir and aquifer properties influence the shape, size and resource potential of ROZs.
Choked Flow in HVO Recovery: Injection and Production in Horizontal Wells
Authors: Burtsev A. , Kuvshinov B. , de Rouffignac E. , Mollinger A. M.
Published: December 2007

The problem of multiphase flows in chokes presents an interesting problem for steam injection and hydrocarbon production. In both cases it is important to evaluate the maximum possible mass fluxes through a perforation. Several models are used in the oil industry for this purpose, e.g., Ashford (1974) [1], Sachdeva et al. (1984) [2], and Perkins (1993) [3]. This paper explains physical principles behind these theories, and outlines their range of applicability. The task of the study is to choose a model that would provide the most general and accurate description of a multiphase flow that can be used for implementation in a reservoir simulator. It is concluded, that existing models are very restricted. They are applicable to particular cases, where the phase transition between the liquid and gas phases is absent. A rigorous description of a multiphase flow with a phase transition does not seem feasible. The possibility of a phase transition introduces a large uncertainty in the flow parameters. This uncertainty essentially exceeds differences between predictions of existing approaches. For this reason, it is sufficiently to analyze flows within the framework of the simplest theory. Such a theory is presented in this report. We derive simple relations to estimate critical flow parameters and transported fluxes. These relations provide a relatively simple evaluation of steam injection and hydrocarbon production without significant loss of accuracy. Preliminary simulation results to illustrate the flow of a wet steam (i.e., two-phase fluid) through the choke are also discussed.
Intelligent-Well Technology Reduced Water Production in a Multilateral Oil Producer
Authors: Ajayi A. , Konopczynski M. R.
Published: December 2007

Excessive water production is often associated with mature fields. The source could be from the aquifer providing reservoir energy or waterflood process used for sweep enhancement. The adverse effect on oil production and reserves requires that a remedial action should be implemented to minimize the overall impact. An effective remedial action requires the identification the source of the problem.

This paper discusses the use of intelligent well completion (IWC) technology to control the amount of water production from a multi-lateral well in a mature asset in order to maximize overall oil production. The multilateral wells were drilled to connect the identified sweet spots and boost oil recovery. The field water cut ranges from 20% to 100% with an average of about 75%. The main challenge facing the asset is improving waterflood efficiency and reducing percent water cut of produced fluids. As a solution, the operator installed a Digital Hydraulic IWC system that allows for isolation of each lateral branch in the producers. This system enables an independent control of the contribution of each lateral for production optimization. This same isolation technology can be applied to water injection wells to improve the waterflooding efficiency. The system consists of remotely operated control valves and downhole packers that isolate water producing areas of the well. An ESP installation is integrated with the provision of a hydraulic disconnect, allowing the replacement of the ESP without affecting the lower completion. The disconnect tool provides re-establishment of hydraulic control line continuity upon ESP replacement.

Production tests carried out after initial installation indicate a significant reduction in water-cut from 99% to 71% resulting in significant increase in oil production. Additional oil ultimate recovery is estimated to be about 0.6x106 STB. This case study demonstrates the ability of the intelligent well system to identify and control the production of unwanted water without intervention, accelerate production, increase ultimate recovery and lower operating cost.
Stochastic Simulation of Marine Reservoirs Through Paleotopography Modeling
Authors: Kedzierski P. , Mallet J. -L.
Published: December 2007

Predicting lithological properties based on accurate and realistic facies models and estimating their heterogeneity are important issues for better reservoir exploitation. While the last trend in reservoir simulations consists in integrating more geological concepts in numerical methods, the proposed approach uses an innovative method binding facies occurrence to landscape attributes, such as water depth, slope angle, or distance to the shoreline. The modeling strategy is first to estimate the variations of the landscape morphology and topography throughout time to then deduce facies probability fields. The assessment of landscape variations is done in the geochronological domain, where the vertical axis is the geological time and the horizontal axes correspond to the paleogeographic coordinate system. This geochronological space is similar to the depositional space before faulting and folding. Stochastic simulations are then applied using the deduced facies probabilities. The suggested approach was applied on a realistic case study to build several realizations of facies models. They are then used as input for stochastic simulations of lithological properties of this reservoir.
Facies Analysis and Architectural Elements Within a Fluvio-Estuarine Sedimentary System: The Lower Cretaceous Bituminous Sandstones of the MacMurray Formation, Alberta (Canada)
Authors: Bailleul J. , Delhaye-Prat V. , Parize O.
Published: December 2007

In north-eastern Alberta (Canada), the fluvio-estuarine McMurray Formation constitutes the main bitumen accumulation of the Athabasca Heavy Oil Province. Deposited within the fluvial-to-marine transition zone, the McMurray clastic succession is characterized by the lateral and vertical juxtaposition of a wide variety of depositional processes. This led to complex lithofacies variations responsible for uncertainties in predicting reservoir heterogeneities.

In this context, a realistic paleogeographic reconstitution is necessary to localize sandy reservoirs and optimize the exploitation of bituminous sandstones. The sedimentological study of the McMurray reservoir, based on outcrops and subsurface data (cores, well logs, seismic profiles), has been undertaken along a 150 km north (distal) -south (proximal) transect.

Facies analysis permits to constrain depositional environments within the McMurray Formation. We document in detail facies associations corresponding to continental (fluvial/palustral/paleosols facies), estuarine (interaction between tide and fluvial processes) and marine environments (wave-tide to wave dominated processes). A particular attention has been paid to the nature, size, geometry and bounding surfaces of architectural elements (i.e. fluvial or estuarine channels, IHS/point-bars, tidal bars, incised valley, emerged surfaces). Stratigraphic correlations, combined with cartographic analysis, allow to evaluate how these sedimentary bodies are related in time and space. The McMurray Formation has been previously sub-divided into three units: the fluvial dominated lower McMurray, the fluvio-estuarine middle McMurray and the marine dominated upper McMurray. We notably demonstrate, on the base of size and amplitude of IHS, that the middle McMurray may be sub-divided into stratigraphic sub-units.

We also point out the significance of oxidized surfaces overlain by abrupt grain size changes. Such surfaces are important clue for sequential analysis and may have a regional extent. They should be taken into account as a potential accurate correlative tool for the McMurray Formation.
New Drilling-Fluid Solution for Unconventional Sand Wells in the San Juan Area
Authors: West G. , Morales L.
Published: December 2007

During the last several years, drilling deviated wells through highly bentonitic shallow formations and unconventional coal bed gas sands in the San Juan area of the Rocky Mountains has indicated the need for fluids as inhibitive as a 7% KCl/polymer system. Operators have experienced advantages with this type of system in terms of wellbore stability, penetration rates, wellbore workability and well productivity. However, increasing environmental restraints in the area make the economics of this system less desirable in terms of haul-off and disposal costs. Core samples of reactive shales in the area were analyzed to determine if a freshwater-based system could be formulated to achieve similar performance to what was previously achieved with the 7% KCl system. Several different freshwater-based muds were tested in the lab, including some high performance water-based fluids. This paper describes criteria that enables a fluid to be called a high performance fluid and reviews the data that yielded a "fit-for-purpose" high performance fluid designed for the specific clay mineralogy of the San Juan area. A field trial was initiated to decide if the lab results could be verified by actual drilling data. Performance data from the trial wells are reviewed and compared directly against the previous successful system. The paper illustrates how a fit-for-purpose high performance water-base mud can help the economics of unconventional gas sand drilling.
Keynote: Megaproject Execution
Authors: Palmer J. , Mukherjee T.
Published: December 2007

In a global project environment where many large projects struggle to meet their cost and schedule targets, Saudi Aramco has been executing its world-class mega projects with ever shorter schedules, and well within budget. Of the five mega projects executed in the last ten years, two were selected as Project Management Institute project of the year, and one was honored at the 2005 International Petroleum Technology Conference.

Saudi Aramco is currently executing a series of new mega projects that will help meet the world-wide energy demand increases and ensure its leadership position for years to come. Huge new gas processing plants, facilities for recovering valuable petrochemical feedstock, and new crude oil production facilities are all a part of Saudi Aramco's ambitious domestic capital program to increase oil supplies and support Saudi Arabia's burgeoning petrochemical industry.

Collectively, the Hawiyah, Khursaniyah, Khurais, Shaybah and Manifa programs will increase revenue to the Kingdom, and promote the local economy by increasing oil production by 2.85 million BPD, sales gas by 1.4 BCFD, ethane production by .45 BCFD, and condensate by 325,000 BPD. All of these projects are being executed on demanding schedules and within budget without a significant increase in Company personnel while expanding the Saudi Arabian procurement and construction content of the projects. This paper will illustrate how this is being achieved.

The paper will also show how Saudi Aramco's Project Management personnel cooperate with our internal stakeholders and contractors to deliver these projects. Integrated teams resolve technical issues swiftly, optimize scope, streamline design reviews and achieve full control of the quality and schedule.

The report will further demonstrate how the use of best practices promotes excellent project results. Our commonly used best practices include Value Engineering, Constructability, Planning for Startup, Benchmarking, Scope Definition & Control and formal use of Lessons Learned.

Saudi Aramco is dedicated to supporting Saudi Arabia's role as the leading provider of energy to the world. History has demonstrated its success. Saudi Aramco will continue to build on the success through innovation, solid integration and a strong will to meet future challenges.
Flow Reversal and Mixing
Authors: Jha R. K. , John A. K. , Bryant S. L. , Lake L. W.
Published: December 2007

Flow reversal provides insights about mixing mechanisms in flow through porous media. We have simulated the effect of flow reversal on mixing in two-dimensional porous media in two different ways. First, we simulate the transport of a tracer slug by solving the Navier-Stokes and convection-diffusion equations in the pore space. This approach allows investigation of solute transport and mixing in simple flow geometries from first principles without assumptions about macroscopic models for mixing. The direction of flow is reversed before solute exits the medium. The simulation studies are carried out for several diffusion coefficients, penetration depths and for several flow geometries. The second approach uses particle tracking to simulate the effect of flow reversal at larger length scales. This approach is free of numerical dispersion, can be used in the absence of diffusion and has no limits on the size of the simulation. It is, however, limited to layered media flow.

The simulation studies presented in this paper explain the mechanism of mixing and the origin of the irreversibility of mixing. We also explain several experimental observations on flow reversal tests found in the literature. Changes in pore morphology significantly enhance mixing in pore space by inducing local velocity gradients and increasing the surface area available for diffusion. This local mixing, caused by diffusion, is irreversible. However, velocity gradient (convective spreading) alone does not cause mixing. In the limit of zero diffusion, on flow reversal, mixing is completely reversible. We show that even a small amount of diffusion is enough to cause irreversibility of mixing. Although seemingly small, diffusion can homogenize concentrations in the transverse direction to flow even at the field scale. Thus it is important to include the effect of diffusion when analyzing miscible displacements in porous media.
Real-Time Fiber-Optic Distributed Temperature Sensing (DTS)—New Applications in the Oil Field
Authors: Nath D. K. , Finley D. B. , Kaura J. D. , Krismartopo B. , Yudhiarto W.
Published: December 2007

Reservoir performance monitoring can provide real-time information that can enable more timely operational decisions to be made. Often, the data can be collected without performing an intervention. This paper will discuss one of the newest reservoir monitoring techniques — fiber-optic distributed temperature sensing or DTS and some of the recent successes provided by DTS that are enabling it to be considered as an integral service for reservoir monitoring.

DTS can provide a temperature profile of the entire wellbore in real time, which in turn, can provide an enhanced understanding of the downhole flow (or injection) profile. Historically, DTS has been a niche service for steamflood and geothermal applications due to its high bottomhole temperature (BHT) survivability. Acceptance of the technology, deployments costs, and value added are the reasons applications outside of steamflood and geothermal wells are being recognized.

This paper presents three cases of non-steamflood applications of DTS. All three cases are from an oilfield in north-central Sumatra, Indonesia. Each illustrates how the use of DTS optimized the completion and/or improved the well/reservoir management strategies. The three cases provided the following services: Determined fluid level for electrical submersible pump (ESP) optimization.Monitored realtime fracture-height growth during a mini-frac treatment.Flow profiled in an artificial lift completion where the producing interval was inaccessible for a conventional production logging test (PLT).
Quality Assurance of the Evaluation of Hydrocarbon Saturation From Resistivity Data
Authors: Worthington P. F.
Published: December 2007

Validated electrical type curves, which collectively describe a continuum of conductivity behavior of fluid-saturated rocks, allow the petrophysical evaluation of hydrocarbon saturation to be set within a generic reference framework. Through the type curves, a reservoir rock can be classified in terms of its electrical character, specifically adherence to, or departures from, classical clean-sand (Archie) conditions and, by corollary, the degree of any shale (non-Archie) effects. The classification guides the approach to future core-data acquisition and to well-log analysis. As part of this process, the type curves allow pre-existing data from other reservoirs to be examined as potential analogs. In these ways, the type curves are used to ensure that interpretative algorithms are appropriate to the petrophysical task in hand.

The application of the type curves using public-domain log data from key wells in seven diverse hydrocarbon reservoirs has illustrated how petrophysical interpretations away from the key intervals can be screened with minimal calibrating information. Comparisons of best estimates of hydrocarbon-filled porosity with previously reported values have indicated a potential volumetric upside in all cases, with hydrocarbon saturations being up to 30 units higher. This is attributed to the generic nature of the screening process, which takes account of the electrical character of a reservoir without any detracting influence from procedural constraints. To further reduce the risk of underestimating hydrocarbon volumes, a set of equivalence charts has been constructed using basic petrophysical properties. These charts provide a quick-look recognition of any departures from the Archie conditions and thence whether the type curves are required.

The screening process has been synthesized into pragmatic workflows, whose adoption should impart additional quality assurance to petrophysical applications.
Intelligent Well Automation—Design and Practice
Authors: Mathieson D. , Giuliani C. , Ajayi A. , Smithson M.
Published: December 2007

The commercial application of Intelligent Well Technology is fast approaching the ten year milestone. Expanding the range of advanced completion and monitoring products with particular focus on reliability engineering has been the main theme for this sector. As this technology has matured, research focus has shifted to Intelligent Field or Smart Field concept studying the potential of wide-scale automation and optimization.

This paper describes the development of Intelligent Well surface control systems, aimed particularly at providing automation and optimization of well based processes as a means to achieve advanced well management. A simple layer model is proposed describing an increasing level of control and automation.

Data standards and connectivity are discussed as the vehicle to achieve wide-scale integration of advanced well management, as this capability is portrayed as one of the stepping stones of Intelligent Fields.
Apparatus for Measuring the Dynamic Solids-Settling Rates in Drilling Fluids
Authors: Murphy R. , Jamison D. , Hemphill T. , Bell S. , Albrecht C.
Published: December 2007

Barite Sag is a reoccurring problem with many oil-based drilling fluids. Attempts to correlate sag tendencies to various rheological properties commonly used to benchmark drilling fluids have had limited success in prevention and anticipation of sag problems in the field. Herein is presented a new testing apparatus for dynamic and static settling rate (sag) measurements, which has been proven to provide a better understanding of the sag phenomena as well as provide a better means to characterize fluid performance. This apparatus greatly expands the precision of sag measurements over previous techniques and allows testing conditions similar to those experienced downhole. Good correlation has been found between settling rate measurements and performance of drilling fluids in the field.
Systematic Approach to the Design and Application of a Well-Fracturing Fluid To Ensure Deepwater Production
Authors: Park E. , Olson K. E. , Weber B. J. , Cawiezel K. E. , Monroe T. D. , DeVine C. S. , Cutler J. L. , Berry S. L.
Published: December 2007

As deepwater exploration projects in the Gulf of Mexico and other offshore areas have gained momentum, development activities in all areas of drilling, completion and production of these wells have faced significant challenges. One key area of concern in completion of these wells is the design, application and compatibility of the fracturing fluid to ensure optimum well performance. Deepwater engineering design and application of fracturing fluids are presented with some unique challenges in well depths that can exceed 20,000 ft with pore pressures greater than 20,000 psi. One major issue facing deepwater fracturing is generating enough bottomhole treating pressure to create a hydraulic fracture at the sandface without exceeding the limitations of the hydraulic equipment at the surface. In order to overcome these surface hydraulic equipment limitations and still create the needed hydraulic fracturing pressure at the sandface, weighted fracturing fluid formulations have been developed to address these issues. Furthermore, due to the increased travel distance to the sandface and the extreme temperature ranges that the fluid is exposed from the mudline to the BHT, the fracturing fluid must have flexibility to be designed to meet specific density, extended crosslink delay times, friction pressures, and compatibility specifications.

This paper summarizes a study to formulate a sodium bromide weighted, delayed crosslink fracturing fluid system to meet the fluid and engineering guidelines for the fracturing application. After baseline fluid formulation studies with the weighted sodium bromide, delayed crosslink fracturing fluid system were designed, rheological performance with breakers at BHT were run, stacked cell regained conductivity lab measurements were performed and friction pressures were determined. Additional studies were also conducted with this weighted fracturing fluid to determine compatibility with the well's produced crude oil and returned permeability studies utilizing formation cores.
DTS Transient Analysis: A New Tool To Assess Well-Flow Dynamics
Authors: Johnson D. , Sierra J. , Gualtieri D. , Kaura J.
Published: December 2007

Distributed temperature sensing (DTS) is a valuable tool used to understand the dynamics of oil and gas production and injection rates. This is achieved by monitoring the temperature variations caused by flow or injection rates at the reservoir entry points. Although most documentation to date has been limited to the discussions resulting from the examination of steady-state temperature profile behavior, significantly more knowledge and better assessment of "what's happening" in wells can be gained when sequences of complete wellbore temperature profiles are analyzed during rate-related or other induced thermal transient events, such as seen in pressure transient analysis.

DTS technology allows complete wellbore temperature profiles to be obtained in a short period of time without the need for wire line. Discrete temperature measurement information can be obtained along the entire wellbore using optical fiber and a laser source/detector to repeatedly pulse light down the fiber and detect the back-scattered light from every depth. The back-scattered light is the result of the interaction of each laser pulse with the fiber molecules and is proportional to the temperature of the glass at a given depth. Intensity responses of repeated light pulses are averaged to obtain acceptable temperature resolution and can be improved by increasing acquisition time.

This paper discusses the value added from transient temperature analysis of DTS profiles for oil and gas wells under production, injection, and treatment conditions. Data taken with DTS technology and thermal simulators from several actual field cases will be provided to demonstrate how these techniques can improve analytical capabilities and how a temperature change has a direct relationship to production/injection layer contributions, reservoir flow properties, tubular leaks, and steam breakthrough locations. The field cases also will demonstrate how a DTS-acquired transient temperature profile analysis can be applied. In addition to the improved data acquisition capabilities, the paper will also provide the cost and safety advantages gained by using DTS transient analysis techniques.
Dynamic Depth Correction to Reduce Depth Uncertainty and Improve MWD/LWD Log Quality
Authors: Dashevskiy D. , Dahl T. , Brooks A. G. , Zurcher D. , Lofts J. C. , Dankers S.
Published: December 2007

Accuracy of MWD/LWD depth measurements can be improved by considering the dynamic variation in drillstring length due to pipe loading under changing drilling conditions. This paper details a new method which uses surface torque, hookload and temperature measurements to determine force distribution in a drillstring and to compute apparent drillstring length. When available, torque, WOB and temperature measured downhole are used to increase accuracy and robustness of the method.

Although logging depth is referred to as a measurement, in reality only the drilling block position is measured. Depth is inferred from it using drillstring length. In recent publications physical phenomena affecting this were analyzed and quantified. Elastic pipe stretch and thermal expansion were found to be most significant. Techniques to compensate for these effects based on empirical formulae have been proposed1, but they provide an averaged correction which has insufficient accuracy for many drilling and formation evaluation applications.

This paper presents experiments covering various wellbore profiles, temperature profiles, and drilling modes. They show that the depth fluctuation may be as much as 2.7 meters with a 7000 meter long drill string even when only the current rig operation mode changes. Among other factors considered in the paper, apparent depth fluctuation is the most significant contributor to commonly observed MWD/LWD log discrepancies when bed boundaries or other features are not logged at the same depth with each sensor. These errors lead to inaccurate petrophysical calculations, distortion of borehole images, and lost time due to depth matching. Case studies illustrate the positive effect of dynamic depth correction on formation evaluation log quality.

The proposed method will improve depth measurement accuracy. This will in turn reduce the uncertainty in computation of reservoir characterization parameters such as net-to-gross and structural dip, especially when data from multiple wells are evaluated together.
Universal Process for Benchmarking Drilling-Fluid Performance
Authors: Zamora M. , McGlaughlin J.
Published: December 2007

A process has been developed to evaluate drilling fluid cost performance for a wide range of planning, intervention, and quality improvement activities. Meant to be universally applicable, the innovative process permits comparisons among similar and dissimilar wells drilled in the same or different global regions. It also can be used to contrast drilling fluid cost performance with operator-driven quality indicators, to classify wells for front-end loading requirements for planning, and to monitor actual-versus-planned performance during drilling.

Methods normally used for benchmarking drilling performance are not well suited for drilling fluids. The approach introduced in this paper is based on a simple ratio that compares mud cost of a well to a corresponding technical limit. The technical-limit relationship, which uses a profile index to characterize well complexity, was derived empirically from a large internal database representing a wide assortment of well types, drilling conditions, and locations.

This paper describes the development and implementation of this process. Several case studies are presented to demonstrate specific applications. Although the process was developed strictly for internal use, full implementation details are provided to encourage its use by others in the industry involved with service-quality initiatives.
Undersaturated Oil Viscosity Correlation for Adverse Conditions
Authors: Bergman D. F. , Sutton Robert P.
Published: December 2007

The determination of viscosity is required for evaluation of the pressure drop resulting from flow through porous media, tubing or pipelines. Viscosity is a necessary property to ascertain well productivity or to properly size tubing, pipelines and pumps. Numerous methods exist to estimate viscosity for computer calculations. Oils encountered in deep water environments are often highly undersaturated - in some cases in excess of 15,000 psi. For transport, the dead oil must be pumped in an environment with temperatures as low as 35°F. At this temperature, the dead oil atmospheric viscosity can be in excess of 500 cp. The pressure required to pump oil through pipelines from deep water can exceed 3000 psi at the pump on the platform and over 5000 psi at the sea floor. The pressure effect on viscosity results in a significant additional increase in this property which can adversely affect pipeline performance. The existing methods for estimating undersaturated viscosity were not developed using data that encompasses the pressure or viscosity range that are currently encountered by the industry. A large database comprised of 1,399 oils and 10,248 data points was constructed to evaluate the accuracy of existing correlation methods. Pressure differentials up to 25,000 psi and viscosity in excess of 1000 cp are included in the database to ensure that viscosity at both typical conditions and the extreme conditions encountered in deep water are represented. The existing methods are shown to be inadequate over this wide range of conditions. A new method was developed that offers improved accuracy and consistency over the expanded range of viscosity and pressure differential.
Evaluation of Horizontal Wells Using LWD Propagation Resistivity and Laterolog-Type Resistivity Logs
Authors: Hu G. , Bittar M. , Hou J.
Published: December 2007

Today, highly deviated and horizontal wells are commonly drilled for better drainage of oil reservoirs. Evaluation of horizontal wells is a challenging task. Traditionally, propagation LWD resistivity logs were interpreted with simplified models. These interpretation methods included using charts, databases, and fast inversion or deconvolution algorithms for resolution enhancement. Many of these traditional methods have limitations in evaluating horizontal wells, particularly when fresh mud is used and borehole size is enlarged. Under these difficult conditions, additional information regarding the formation around borehole will help to reduce the uncertainties in formation evaluation.

Theoretical study has shown that a particular LWD laterolog type tool, known as a "toroidal type" LWD resistivity tool, brings in additional information with significant bearing on practical formation evaluation. The additional information makes it possible in horizontal wells to study formation anisotropy and invasion effects with greater confidence.

This paper briefly introduces the operating physics of the two types of LWD resistivity tools (propagation vs. toroidal). The paper also introduces the modeling methods we have developed. Limitations and advantages of propagation phase resistivity and laterolog type focused resistivity are studied in a horizontal well drilled with fresh mud. Conventionally, when relative dip angle between borehole and formation exceeds 80 degrees, this well can be regarded as a horizontal well.

We will show how the combination of the two types of resistivity tools facilitates horizontal well evaluation in wells drilled with fresh or salty mud.
Investigation of Gas Carryover With a Downward Liquid Flow
Authors: Sutton R. P. , Skinner T. K. , Christiansen R. L. , Wilson B. L.
Published: December 2007

An investigation into gas carryover resulting from the downward flow of water was conducted. Water accumulation in a gas well is responsible for well productivity decline and left untreated will eventually result in the well loading up and ceasing to produce. Submersible pumps offer a viable means of removing water from the well; however, gas interference can significantly degrade pump performance and even result in pump failure. An effective means of mitigating this problem is to place the pump below the producing interval effectively allowing gravity to separate gas and water. The rule of thumb in this instance is to limit the downward liquid velocity to values less than 0.5 ft/sec to ensure gas/water separation. High steel prices dictate smaller casing strings be utilized where possible in order to enhance project economics in operations such as coal bed methane. However, smaller pipe sizes result in higher flow velocities for a corresponding surface flow rate. These higher flow velocities reduce separation efficiency, which could jeopardize project success. In order to quantify the relationship between gas carryover and liquid velocity, a full-scale model was built and actual gas carryover rates were measured. Two sizes of annular flow geometries representative of those used in the field were used in the test. The results were also confirmed with separate measurements taken from a test-well facility. These studies show the traditional rule of thumb value of 0.5 ft/sec to be conservative. Multiphase flow pattern maps were also integrated into the study as supplemental aid into development of operation guidelines and to add insight into operational practices of submersible pumps. As a result of this work, smaller casing sizes were successfully used resulting in substantial project cost savings.
An Accurate Method for Determining Oil PVT Properties Using the Standing-Katz Gas Z Factor Chart
Authors: Sutton R. P.
Published: December 2007

An accurate technique for estimating oil PVT properties using the Standing-Katz Z factor chart has been developed. Prior work to derive tuned gas pseudo-critical property values which provide consistent and accurate compressibility factors has been extended to oils.

Data from 1,099 worldwide oil PVT reports with 11,960 density measurements has been analyzed. The oils studied have API gravities ranging 10.6-63 with gas-oil ratios ranging 5-4,631 scf/STB. Bubblepoint formation volume factors range from 0.98-4.58 Bbl/STB. Saturation pressures ranged from 60-10,326 psia at temperatures ranging 50-332 °F with pressure differentials to 18,491 psi.

The resulting work shows that oil pseudo-critical properties can be correlated with molecular weight as with gases. The resulting relationships can be used to accurately determine saturated and undersaturated oil density. Oil PVT properties such as formation volume factor and isothermal compressibility can then be derived from fundamental relationships with density.

Since the new method correlates properties with the molecular weight of the wellstream, the chemical nature of the oil (ie naphthenic, paraffinic, etc) is considered. Existing correlations (30 for bubblepoint oil formation volume factor and 17 for isothermal compressibility) have been identified in the literature. These methods are tested against the database along with the new method to determine accuracy and recommended procedures. Isothermal oil compressibility has historically proved difficult to correlate with errors typically in excess of 30%. The proposed method significantly reduces the error in calculated isothermal compressibility when compared with traditional methods.