bluuebunny/crossref_metadata_2025 huggingface dataset:
Remediation of Hydrate Plugs in Offshore Wells via Capillary Tubing—A Cost Effective Alternative
Authors: Gounah Tony , Renfro Kevin D. , Bolding Jeff , Embrey Mark
Published: September 2008

Description: A new, cost-effective, time-saving alternative for removing hydrate plugs offshore has been successfully applied three times in the Gulf of Mexico. By using 3/8" tubing and a capillary tubing unit, chemicals can be delivered directly to the top of the hydrate plug, allowing the plug to be dissolved.

Application: Gas hydrates have long been a concern for operators in offshore gas wells. In the Deepwater Gulf of Mexico, the water temperature at the mud line can be as low as 34 F. This presents a potential problematic area for hydrate plugs to form as a result of the extreme temperature changes experienced in the well. Many remedial actions have been used to remove hydrate plugs in the past. These former methods are very expensive due to high operational costs and many days of non-productive time (NPT). A new option provides operators with a high chance of success while saving a considerable amount of money and greatly reducing NPT.

Results, Observations, Conclusions: A capillary tubing unit was used to snub 3/8" OD stainless steel tubing into the well. Once the tubing reached the plug, methanol was pumped at a rate of 1-2 gallons per minute until the plug was completely dissolved over a distance of 160 ft. So far, this technology has been 100% successful. By delivering the chemical directly to the plug, the chance for success is greatly increased. Depending on the size of the production tubing, penetration rates into the hydrate plug average 20 ft/hr, which is much faster than the traditional method of bull-heading. Chemical costs can be reduced considerably because the method uses only 1 bbl of methanol per 10 feet of hydrate plug in 3-1/2" tubing. Rigging up can be accomplished in hours instead of days, reducing operational costs and NPT substantially.

Significance of Subject Matter: Many wells are being left off production for long periods of time due to the high costs and operational issues involved with bringing in large coiled tubing units or workover rigs to remove a single hydrate plug. This new method allows operators to safely and effectively remediate the obstruction with minimal lost production time.
A New Look at Wellbore Collision Probability
Authors: Brooks Andrew G.
Published: September 2008

Given the potentially catastrophic human and environmental results of an unplanned well collision, a meaningful estimate of the probability of wellbore intersections provides a valuable risk management tool. A number of estimation techniques are currently in use in the industry; however, all of these have limitations which may not be clearly understood. For example, many computations currently in use fail when the two wells are parallel, they ignore the fact that the drilled well may have reached its current location without collision, or they return an identical result regardless of whether the drilling well is thought to be approaching or departing from the existing well.

A rational approach to the problem begins by clearly defining the probability to be estimated. This paper presents a method to ascertain the probability that a particular interval of the well being drilled might intersect an existing adjacent wellbore. An overall collision probability can then be obtained by combining the probabilities associated with successive intervals along the reference well. The estimates of probability are based on knowledge of the surveyed wellpaths and their survey uncertainties, expressed in the form of position covariance matrices.

A body of relevant research exists in the field of astrodynamics, concerned with estimating the risk of collision between orbiting satellites. This paper draws on prior work from both the oilfield and aerospace in developing a more rigorous assessment of collision probability, overcoming the limitation of previous methods. Examples demonstrate that the new method agrees with analytic results for both parallel and non-parallel wellpaths in simple cases where both wells are straight in the region of interest.
PVT Data Quality: Round Robin Results
Authors: Stephen A. G. , Bergman D. , Dodd T. , Kriel W.
Published: September 2008

Compositional data is a vital input to many engineering models, including the calculation of the mud free properties of reservoir fluids sampled by repeat formation testers and calculating the value of gas sold on a calorific value basis. For all such applications, the quality of compositional data is of critical importance. The impact can be material in a wide range of issues, including reserves estimation, facilities design, gas hydrates prediction and sales gas valuation. The main aim of this study was to set quantitative criteria for screening laboratories prior to tendering for a PVT contract.

Reliance on contractor quality assurance procedures is not sufficient. Routine internal consistency checks may not identify some of the errors. Evaluation based on analyses of identical field samples relies on one data set being of high quality, an assumption that may not be correct. There is a need for an independent supplier of high quality gas, liquid and live fluid samples of accurately known compositions that can be used by laboratories to demonstrate the quality they can achieve to the oil companies before unique and valuable samples are sent to them for analysis.

The results of a "Round Robin" evaluation of PVT laboratories around the world are presented. A set of identical samples was sent to each laboratory – 3 dry gases, 3 stock tank liquids and one live sample. There was considerable variation in the quality of compositional analyses reported. A small minority of the laboratories tested generated compositional data that fully met the highest quality measures for both gas and liquid analysis. A similar number were close to meeting these standards, but the majority generated data that was deeply flawed in some respects. In one case, interpretation errors resulted in 24% reduction in C4+ in all the gases. The resulting calculated calorific values were as much as 5% low – a large potential loss of value if used to calculate the value of sales gas. All laboratories were given feedback, and some are actively engaged in resolving the problems identified.
Numerical Modeling of the Slit Mode of Cavity Evolution Associated with Sand Production
Authors: Detournay C.
Published: September 2008

The development of localized bands associated with concentration of compressive strain has been linked to the slit mode of cavity expansion observed in hollow cylinder tests to study the mechanism of sand production. A comprehensive numerical model should account for this compaction mode of failure to predict the amount and rate of sand production with some confidence. This paper documents progress in the development of a numerical model to predict the amount and rate of sand production at a macro-scale (wellbore or perforation) using a continuum hydro-mechanical description of the rock mass. First, we review the general conditions for the compaction mode of failure to occur in the context of a simple cap constitutive law and give examples of numerical simulations that illustrate band formation in a (dry) Hollow Cylinder test. Then, using numerical experiments, we show that the sand production model, enhanced with a cap constitutive law, is able to reproduce qualitatively the slit mode of cavity evolution that has been observed in laboratory settings. In the simulations, the slit mechanism develops as a combination of volumetric collapse (compaction band formation) and transport of failed material by hydrodynamic forces. The sand production curve for this particular simulation shows a monotonic increase in sand-mass versus simulation-time. With the documented enhancement, the sand production model can reproduce three main modes of failure: tension, shear and compaction. The sand production model needs to be validated further and calibrated using laboratory experiments. However, at this stage, it shows good potential as an engineering tool to help characterize the impact of rock strength on sand production associated with oil production.
DTS Monitoring of Hydraulic Fracturing: Experiences and Lessons Learned
Authors: Sierra Jose , Kaura Jiten , Gualtieri Dan , Glasbergen Gerard , Sarker Diptabhas , Johnson David
Published: September 2008

Real-time monitoring of hydraulic fracturing using fiber optic distributed temperature sensing (DTS) is starting to be used to estimate fracture initiation depth, vertical coverage and number of generated fractures, effects of diverting agents, and undesired flow behind casing. DTS monitoring of flowback and production can also help to assess the effectiveness of the stimulation treatment.

To successfully achieve the monitoring objectives, aspects such as fiber deployment, fiber integrity at high injection rates, location and thermal coupling of fiber with respect to flow path, frequency of data acquisition and resolution, and real-time visualization and modeling need to be carefully considered.

This paper presents experiences in the analysis of transient DTS data acquired during high-rate, multi-stage hydraulic fracturing in vertical, deviated, and horizontal oil and gas wells. The location of fiber, conveyed with coiled tubing inside the flow path or cemented behind casing, has a major impact in the temperature response, depending of the thermal conductivity between the fiber cable and the injected fluid path.

When the fiber is hung inside casing, the fluid distribution can be challenging, especially if the deepest fluid leak is closer to the bottom of the treated interval, because the temperature along the fiber very quickly becomes equal to the fluid temperature with a minimum gradient straight-line pattern due to high fluid rate and velocity. To overcome this condition the use of induced hot/cold thermal tracers together with temperature modeling has been introduced, allowing the calculation of fluid rate distribution along the perforated intervals.

Where the fiber is cemented behind casing, well defined patterns, based on the temperature value, can be recognized to discriminate between flow inside and behind casing, allowing out-of-zone fracture assessment. The thermal coupling of the fracturing fluid inside the casing and the fiber can be very weak at certain levels where small gas "insulation" pockets occur around the fiber, keeping the fiber temperature closer to the geothermal than fluid temperature. At clamp depths or well cemented zones, fiber temperature is much closer to fluid temperature, because the thermal coupling is strong at these levels. When the fracturing fluid flows behind casing, due to bad cement isolation, reaches the fiber cable, the temperature becomes essentially equal to fluid temperature.

The advantages and limitations of both cases are discussed based on the type of well, length of gross pay, fracture design, treatment rate, and type of fluids.
Development and Field Application of a Low pH, Efficient Fracturing Fluid for Tight Gas Fields in the Greater Green River Basin, Wyoming
Authors: Gupta D. V. S. , Jackson T. L. , Hlavinka G. J. , Evans J. B. , Le H. V. , Batrashkin A. , Shaefer M. T.
Published: September 2008

Hydraulic fracturing has proven to be one of the best technologies to improve productivity from tight gas wells. In such low-permeability reservoirs, careful consideration must be given to fracturing fluid selection. Some reservoirs are under-pressured and require the use of energized fluids, while others are sensitive to water-based fluids due to clay swelling and migration.

Proppant pack damage due to gel residue is one the primary causes of low production rates after hydraulic fracturing treatments. To minimize the damage and therefore maximize production, a new premium highly efficient fracturing fluid was developed. This premium system incorporates low polymer loading carboxymethyl guar polymer and a zirconium-based crosslinker. An adjustable crosslink delay makes the fluid ideal for deep well fracturing and coiled tubing treatment as frictional pressure losses can be minimized. The system can be energized or foamed with carbon dioxide (CO2) and nitrogen (N2) or may also be used in binary foam systems.

This paper will provide details on the new fracturing fluid system, in terms of proppant pack cleanup, rheological properties and fluid loss as well as other parameters. Various rheological evaluations using high-pressure, high-temperature rheometers as well as a foam loop; fluid leak-off testing; and proppant pack conductivity and regain permeability evaluations are presented.

Field case histories will evaluate fracturing treatments using new fracturing fluid and comparable treatments using conventional fluid. Normalized production data of the treated wells of both systems are also compared.
Corroded Casing: Testing of Sealing Capability and Retrievability of a Swelling Elastomer Packer
Authors: Pradie Emmanuel , Jaafar M. Rushdan , Barnes Chris , Gjelstad Geir , Smith Peter E.
Published: September 2008

Globally, many thousands of potentially productive oil and gas wells suffer internal corrosion due to H2S, CO2, and other produced gases and liquids. This limits their capability to provide a packer sealing area suitable for traditional mechanical production packers. Total E&P Qatar planned a recompletion using intelligent well technology in a well in which they expected to find some corrosion. Before initiating the recompletion, they investigated the use of alternative packer technology.

Swelling elastomer packers have been used worldwide in many applications, but verification was required in this case to assess whether such packers would hold pressure in a corroded section of casing. In addition, testing was also was needed to assess whether the completion could be pulled in the event that it became necessary to retrieve the components from the well.

A swellable packer with multiple cable feed-through was designed and manufactured to approximately two-thirds size of the originally specified packer. A sample of corroded casing, supplied by Total E&P Qatar, was used to build a test jig. The jig was equipped to simulate and record pressure, temperature, and other downhole conditions. Theoretical simulations were performed to assess the force required to overcome the anchoring forces applied by the swelled elastomer and were verified by a pull test.

It is expected that with a reliable sealing mechanism for these older wells, technically and financially viable workovers and re-completions can be performed, thereby extending field life and adding to recoverable reserves.

This paper describes the application and test procedures along with the verification and results of the testing performed.
A Structured Approach for Probabilistic-Assisted History Matching Using Evolutionary Algorithms: Tengiz Field Applications
Authors: Cheng H. , Dehghani K. , Billiter T.
Published: September 2008

Model calibration or history matching has commonly been conducted on a single deterministic model by a "manual" trial-and-error approach. With recent advances in the application of design of experiments for using numerical models in probabilistic forecasting, the feasibility of the manual history match process used for a single deterministic model has become questionable.

In manual history matching, a structured approach is used in which the sequence of adjustments has been from global, then to flow units, followed by local changes in model properties. However, the applicability of this approach to probabilistic history matching has not been demonstrated. Moreover, the industry's lack of experience in using assisted history-matching tools and the careless application without using a structured logic that is based on engineering judgment can lead the users to several potential pitfalls resulting in unrealistic solutions.

This work shows that in using evolutionary algorithms, a structured (staged) assisted history-matching methodology can be applied by considering probabilistic ranges of relevant input parameters and tailored objective functions for each stage of the process. The key "heavy-hitter" parameters with the highest impact on the history-match process are identified and introduced through conducting sensitivity runs.

A physically-sound and proper set of parameters with realistic ranges are introduced at each stage of the history-match process in a logical order. This paper shows that a workflow can be designed so that the ranges of selected parameters that are used to attain the best solutions at each stage can be carried over to the next stage to continue the history-match process.

Since this workflow is conducted in a probabilistic semi-automatic manner, a diverse set of solutions can be obtained with the flexibility to guide the process as is traditionally done in manual history matching. The workflow is demonstrated through its application to history match production data from the Tengiz super-giant carbonate oil field located on the shores of the Caspian Sea in the Republic of Kazakhstan.
Extended-Stroke Downhole Power Unit Successfully Pulls Subsea Wellhead Plugs in the Gulf of Mexico
Authors: McDaniel Dennis , Cromb John , Walton Jim , Clemens Jack , Moore Darrell , Huggins Jeff
Published: September 2008

Today's need to provide deepwater subsea well servicing has created many new challenges for the industry. For example, pulling a deepwater subsea wellhead or crown plug can require an extreme pulling force. The difficulties experienced can be compounded by conditions when the plug has been in place for extended periods of time as well as the more demanding deepwater conditions, such as high differential forces and settlement on top of the plug that contribute to the need for the higher pulling forces. These conditions often exceed the capabilities of conventional slickline services. As exploration continues to venture into more challenging environments, service companies have had to increase the scope of capabilities of their equipment to meet the challenges brought about by the new environments that require capability for tools to pull high tensile loads. The deepwater subsea arena has been particularly challenging, and this paper will focus on a slickline innovation — an extended-stroke electro mechanical device — that can provide deepwater subsea well interventions more cost-effectively than other service alternatives.

The tool is a slickline-deployed electro-mechanical device that is operated by batteries rather than explosives or hydrostatic pressurized tools and can produce a high linear pulling force. Since first being introduced, the electro-mechanical device has undergone several changes that have increased its capabilities and functionality. For example, it has recently been configured for pulling subsea wellhead plugs.

This paper will present three case histories that discuss the first use of the ‘extended stroke’ electro mechanical device in the Gulf of Mexico in which it was capable of pulling plugs at a water depth of 5,339 feet as well as several subsequent case histories.

Using the slickline electro-mechanical device rather than coiled-tubing resulted in substantial savings in both the cost of deployment and rig time.
What Does Sustainability Mean to Petroleum?
Authors: Ebenhack Ben W. , Martinez Daniel M.
Published: September 2008

Sustainability can be a troublesome concept that many people find challenging even to define. The most commonly used definition is the one put forth for sustainable development by the Brundtland Commission in 1987: "development that meets the needs of the present without compromising the ability of future generations to meet their own needs." The term sustainability came into vogue on the heels of this report, which was published in a book entitled Our Common Future.i

The Brundtland Commission definition alludes to a balanced, judicious use of resources to provide decent lives for humanity both now and in the future. It is fundamentally a concept of equity; appreciating the needs of all people living and not yet born. This is a powerful challenge to the industries and people engaged in natural resource utilization.

The term sustainability has often been narrowed to refer to the mere longevity of an organization, group, or profits. This is myopic. Without appropriate attention to the sustainability of critical resources, nothing else is sustainable.. Likewise, this term has somehow pitted the valued petroleum resource against what are still speculative technologies (i.e. the alternatives) rather than addressing how we must judiciously use petroleum now to benefit our future.

Beyond that, the dominance of a global resource economy creates a profound set of connections across the world. The industrialized world depends on energy imports from around the world. At the same time, it places everyone in the world in competition for the same resources, as scarcities loom. Recognizing these connections can support a strong utilitarian motivation to consider equitable access to resources.
Directional Success in the Canadian Rockies: Dynamic Tools Enable Accurate Comparison of Drill Bit Designs
Authors: Barton Steven , Lockley Russ
Published: September 2008

A smooth torque response is widely regarded as one of the greatest challenges when drilling with a drill bit on a directional assembly. Aspects such as toolface control and stick-slip are both proportional to the torque generated by the bit, and by nature, fixed cutter (FC) drill bits are capable of generating high levels of torque. If large changes in downhole torque are produced while drilling, these will cause rotation of the drill string, and loss of toolface orientation. This results in inefficient drilling and increases risk of bit and downhole tool damage.

This paper reviews the field performance of a number of drill bits within the Canadian Rockies on directional assemblies. Particular focus is placed on the torque response and its resultant effect on both the steerability and stability of the assembly. The analysis includes comparison of conventional FC drill bits and roller cone (RC) designs, and also documents performance of specific FC designs that are equipped with torque controlling features. These features, in combination with specific cutting structure layouts, are engineered to provide predictable torque response while being optimized for high rates of penetration. The bit designs also include a unique gauge geometry that was engineered to reduce drag and deliver improved borehole quality.

The field performance review includes downhole dynamics data analysis. The recorder used gathers drilling dynamics data at a high frequency sample rate, enabling lateral stability and the variance in downhole rotation of the drill bit to be accurately determined. Evaluation between the different drill bit concepts revealed that use of FC designs with specific torque control features provided toolface control equal to or greater than a RC design. Steerability and stability were improved when compared directly to conventional fixed cutter designs, with resultant increase in penetration rates. Successful application has resulted in significant time and cost savings to operators.
Next-Generation Perforating System Enhances the Testing and Treatment of Fracture Stimulated Wells in Canada
Authors: Bell M. R. G. , Cuthill D. A.
Published: September 2008

Ineffective perforation can adversely affect the completion of fracture stimulated wells in several ways. If the interval is to be tested prior to fracturing, a clean connection to the formation is required to facilitate meaningful data acquisition. Excessive perforation damage can mask true formation potential and lead to incorrect diagnosis and decision making. Inadequate perforations can result in significant fracture tortuosity, increasing formation breakdown pressure – occasionally beyond the capacity of surface equipment or design rating of the well. Finally, limited entry perforation – a common technique for diverting a treatment across multiple fracture initiation points – demands that as many perforations as possible are open and can accept treatment fluids. Low perforating efficiency and variations in perforation cleanup associated with heterogeneous formations can cause uneven treatment distribution and suboptimal completion.

Traditional methods for achieving clean perforations depend on creating a pressure gradient between formation and wellbore to induce flow and remove debris from the perforation tunnels - this can be difficult to accomplish, especially in low-pressure reservoirs. Underbalance cleanup favors intervals with higher flow potential – typically those with greater permeability - and may result in low perforation efficiency in poor or variable quality zones. Operators of wells requiring fracture stimulation are therefore faced with a significant challenge to find reliable, cost-effective perforating methods.

A new class of reactive shaped charges has recently been introduced that generates a powerful secondary effect within each perforation tunnel immediately after it is formed. The reaction supercharges each tunnel, causing a surge of flow into the wellbore that removes all compacted debris and the near-tunnel crushed zone that would otherwise impair flow performance. Since this effect is independent of rock properties and wellbore conditions, a very high percentage of clean tunnels can be obtained across the entire interval without necessarily perforating in an underbalanced condition.

This paper describes the new charge technology in greater detail and reports on its successful deployment in more than a dozen wells for different operators in Canada. Specific examples are used to illustrate how the system facilitates pre-frac evaluation, fracture initiation and limited entry fracture stimulation.
Development of an Expandable Liner Hanger With Increased Annular Flow Area
Authors: Jackson Tance , Watson Brock , Moran Larry
Published: September 2008

Several criteria are important for a cementing operation as it relates to effective zonal isolation. First of all, studies have shown that cementing operations can be improved by rotating and reciprocating the liner. In addition, it has been shown that increased flow rates (prior to cementing, during cementing, and during displacement) can improve zonal isolation. While currently available expandable liner hanger technology can achieve the required liner movement, rotation, and reciprocation to affect a good cement job, these capabilities alone have not been capable of always meeting cementing needs in every scenario.

When expandable liner hangers were introduced to the oilfield, they were immediately accepted. Experience has shown that increasing flow rates (prior to cementing, during cementing, and during displacement) can offer improved zonal isolation. A new liner hanger was designed to increase the annular flow area, subsequently reducing annular friction pressure to allow higher flow rates. The added bypass area would also provide reduced surge to the formation while running the liner. This would shorten liner installation times. In addition, by increasing the bypass area, the possibility of solids bridging at the liner hanger (which can cause loss of circulation during circulating and cementing) would also be reduced. When loss of circulation occurs, proper cement placement is jeopardized.

This paper highlights the development of the new smaller-outside-diameter (OD) expandable liner hanger. This project was commenced; the new liner hanger has a pre-expansion maximum outside diameter that is smaller than the outside diameter of conventional liner hanger's tie-back receptacles and integral top-set packers. The new smaller diameter expandable liner hanger maintains the desirable features of existing expandable liner hanger.

Computer modeling including Finite Element Modeling (FEA) will show the design analysis for the expandable liner hanger. Additionally, prototype testing will be performed to validate the new design.

The new expandable liner hanger design offers the capabilities to rotate and reciprocate during circulating/cementing and displacing; a simple, robust design for installation reliability; and gas-tight liner-top sealing.
Determining Multilayer Formation Properties from Transient Temperature and Pressure Measurements
Authors: Sui W. , Zhu D. , Hill A. D. , Ehlig-Economides C. A.
Published: September 2008

Multilayer transient testing commonly relies on a series of step rate changes in surface flow rate with acquisition of stabilized rate profiles before each rate change and stationary downhole transient rate and pressure measurements after each rate change. The procedure requires one rate change for each layer to be characterized, and overall test duration can be quite long depending on the number of layers to be characterized. This study introduces an entirely new testing approach that uses transient temperature data at multiple locations together with a single-point transient pressure measurement. Because the temperature sensors acquire multipoint temperature simultaneously, this technique requires only one surface flow rate changes, thereby reducing the test duration significantly.

A coupled wellbore/reservoir thermal model developed in a previous study showed that the combination of transient temperature and pressure is sufficiently sensitive to individual layer properties to determine layer permeability and skin values in multilayered systems. In this work, the inverse problem is solved using the Levenberg-Marquardt regression algorithm.

In this new testing method, temperature data from only n+1 locations are required to determine layer permeability and skin values in an n-layer reservoir, and strategic sampling over time accelerates the regression convergence. The inversion has been tested on many synthetic cases with wide variations in layer permeability and skin values and has proven to be both accurate and robust. In addition, temperature resolution and data signal to noise impacts have been studied along with a data filtering approach that enable selection of suitable pressure and temperature sensor technologies for applying the new testing method. With the interpreted permeability and skin values, well productivity can then be enhanced by hydraulically fracturing in low permeability layers and/or by applying matrix stimulation in layers with high skin.
An Integrated Approach to Reservoir Uncertainty Assessment: Case Study of a Gulf of Mexico Reservoir
Authors: Sharma A. , Leung J. , Srinivasan S. , Kim Y.
Published: September 2008

Integrated uncertainty analysis of a carbonate reservoir in the Gulf of Mexico was performed to quantify the contribution of factors such as lithofacies definition criteria, reservoir structure, total and fracture porosity, net-to-gross cut-offs, and measurement scale disparities on geologic uncertainty. An innovative approach to derive facies definition criteria and net-to-gross cut-offs based on k-mean cluster analysis is presented. A detailed analysis of scale up of petrophysical properties using the variance of mean concept was performed and its implication on geologic model uncertainty was assessed. Finally, innovative approaches to verify and visualize spatial uncertainty models are presented.

A detailed geologic model for the fractured carbonate reservoir was available and the study objective was broken down into an assessment of uncertainty due to: i) structural model, ii) sedimentary model, iii) petrophysical model, and iv) scaleup/upscaling. Systematic investigation of each of these aspects as well as a fully probabilistic integration of uncertainty models was performed.

Uncertainty in original oil in place was computed by sampling from the component distributions. The study results indicate that the OOIP exhibits significant sensitivity to factors such as cut-offs for lithofacies and net-to-gross definition. An important result that points to a paradigm shift in uncertainty modeling is the sizeable contribution of scale-up to the uncertainty models. The results further reveal that the determination of net-to-gross and lithofacies definition thresholds using cluster analysis vastly enhances the accuracy of the prediction of net-pay at a new well location.

The paper presents a complete workflow for integrated reservoir uncertainty assessment. Besides demonstrating the use of data analysis tools such as cluster analysis for deriving more robust criteria for facies and net-to-gross definition, a fundamental contribution of this paper is to demonstrate the role of scale up on uncertainty assessment. While this has been alluded to by several researchers in the past, this paper is the first to demonstrate a modeling workflow that explicitly handles uncertainty due to scale up and promotes the notion of "soft" conditional simulation.
Entrance Pressure of Oil Based Mud into Shale: Effect of Shale, Water Activity, and Mud Properties
Authors: Oleas Andres , Osuji Collins E. , Chenevert Martin E. , Sharma Mukul M.
Published: September 2008

Oil-based muds (OBMs) have been developed to combat drilling problems often caused by shale hydration. Therefore, it is of utmost importance to understand the interaction of OBMs as they contact shales. Past research (Chenevert 1970) has shown how the movement of water from OBMs can be controlled by the addition of salt. This paper deals with the movement of the oil phase of the OBM, as described by its hydraulic "Entrance Pressure." Although the oil filtrate of the OBM does not hydrate the shale, it can penetrate and flow into the shale at a certain entrance pressure. Such flow into shale can be as damaging as water flow, because it increases the pore pressure of the shale, which can cause wellbore failure. It is of primary interest to understand this when using OBMs in shales. It is also important to understand how factors such as the emulsifier concentration in the OBM and the porosity of the shale affect this entrance pressure.

The objective of this study is to perform laboratory tests in order to determine and quantify the factors that control the entry pressures for shales. For this purpose, five OBM samples with different emulsifiers and oil and water concentrations were prepared. The study was also intended to derive an understanding of the effects of shale porosity on entrance pressure. In order to vary the porosity of the test samples, it was convenient to place them in various controlled environments with relative humidity (i.e. water activities). Data are reported for Arco China shale samples having porosities of 1.8% (native), 3.9%, and 4.9%, at water activities (aw) of 0.72, 0.86, and 0.96, respectively.

It was observed that as the emulsifier concentration increased, the oil breakthrough pressure increased. It was also observed that as the porosity of the shale is reduced (smaller pore throats), the entrance pressure for the mud increases.
Petrophysical Properties Prediction Using 3D Core Scanner Imagery
Authors: Jouini Soufiane , Umbhauer Francois , Leduc Jean-Pierre , Keskes Noomane
Published: September 2008

This paper deals with the use of core scanner imagery for discriminating main representative rock textures, to improve core high resolution petrophysical log quality and to propose a better strategy for plugs sampling. The idea of using tomography images has physical bases. In fact, scanned data is representative for rock bulk density changes; the perceptual texture of these images reveals features like granularity, mineralogy, both tied to porosity distribution. In this paper we demonstrate that, core scanner images contain information that can be related to petrophysical properties. This paper presents a fully automated method based on a stochastic approach for textural analysis and segmentation of core scanner images. The technique used to obtain image models is related to new image processing techniques based on texture models. The accuracy of the model is a key point for confidently linking images and physical or geological properties. This approach is demonstrated through stochastic synthesizing procedure proving a fundamental link between texture perception and rock physical properties. The proposed workflow is (i) to use 3D scanned cores images as a vector of continuity for automatically describing petrophysical facies and (ii) to extrapolate petrophysical properties along cores in order to produce a high resolution core petrophysical log.

A validation of this method is provided through comparison with "hand made" petrophysical facies description. Synthetic petrophysical properties curves have also been compared to curves issued from conventional kriging of core data. Blind test procedures were used to evaluate the efficiency of our technique in regard to porosity, density, Archie's formation and cementation factors and mineralogy (clay volume). Also, as lower performance is observed for permeability estimation an alternative solution is proposed for improving the prediction of this latter property.
Experimental and Theoretical Investigation of Clogging Processes near Production Wells using X-ray Tomography
Authors: de Zwart A. H. , Currie P. K. , de Boer J. , Naeini Alireza Vafaie , Schotting R. J.
Published: September 2008

Formation damage in production wells has been less studied than in injection wells. In injection wells, decline in well injectivity can occur, due to fine particles suspended in the water. These particles are deposited in the reservoir, blocking the pores, causing reduction in the permeability of reservoir rock near the well. Thus, the decline is due to injected water quality and reservoir properties.

In production wells, particles can be transported through the reservoir and cause formation damage. The damage is caused by deposition near the wellbore as a result of the converging flow geometry. As is briefly discussed, it is a common problem in the water industry, where water production wells suffer from productivity decline due clogging of the aquifer near the wellbore. The accumulation of particles causes plugging of pores and decreases the permeability creating a damaged zone near the well. This results in extra, expensive cleaning operations and early shut-in of producers.

This paper reports on an investigation on particle deposition in converging flow geometry, modeling oil and water production wells. Parameters are varied to study the effect on particle deposition of flow rate, particle concentration and particle/grain aspect ratio. The experiments use a converging-flow unconsolidated sand-pack. A hematite particle suspension is injected into the sand pack to observe clogging effects. With the aid of a CT-scanner (X-ray tomography), deposition profiles in time are obtained. Effluent particle concentrations and pressure profiles are also measured in real time. The results of the experiments are interpreted using deep bed filtration theory in converging flow geometry. The experiments show a clear effect of converging flow geometry on particle deposition.
Field Testing of an Automated Well Tester in Extra-Heavy and Diluted Oil Application
Authors: Bastardo Rafael , Imam Asher , Scoglio José
Published: September 2008

In the past, gas-liquid cylindrical cyclone (GLCC) technology was chosen mainly for low viscosity applications, where liquid and gas phases could be completely separated from the mixture and measured independently. Due to its reduced footprint, investment cost, and simplicity, this turned out to be an attractive solution for oil industry applications. However, the practice of not using GLCC technology when handling heavy oils became a model. This model shift happened because of GLCC's short residence time, poor separation efficiency, high gas carry-under (GCU), and limitations of single-phase flow-metering instruments.

The main improvement made to this technology, was finding an efficient way to separate a majority of gas from heavy-oil mixture and finding a combination of metering technologies able to handle certain amounts of GCU without affecting liquid-rate accuracy.

The evaluation program was conceived to test the behavior of a partial separation system (PSS) when handling extra-heavy and diluted oil. A total of 42 tests were performed on 16 wells from 3 well pads.

The diluent injection rate was determined to be one of the main parameters impacting the PSS performance and liquid metering accuracy. It was observed that the variation in the diluent percentage impacted the liquid metering by over- or under-estimating the total liquid measurement. High viscosities and foamy mixture effects were countered by making minor adjustments to the GLCC level control and instrument configurations.

Based on the success criteria, the PSS evaluation was qualified as successful. The system proved to be ±10% accurate on total liquid-volume measurement with a confidence interval of 90%. Regarding repeatability, a maximum deviation of 1 to 2% was shown under normal well operating conditions.

For water-cut measurements, the objective was to measure within ±5% of the actual value without performing individual well calibrations. Testing of fluctuations in extra-heavy oil properties and concentration of diluent, as well as field conditions, proved that a ±5% accuracy for the water-cut measurements could be achieved if individual well calibrations were performed.

Throughout the entire duration of the project, the PSS, with its flexibility and ease of operation, maintenance and diagnostics, proved to be a solution for extra-heavy and diluted oil applications in the Orinoco Belt of Venezuela.
Drilling Hard and Abrasive Rock Efficiently, or Generating Quality Cuttings? You No Longer Have to Choose…
Authors: Desmette Sébastian , Deschamps Benoit , Birch Ron , Naegel Matthieu , Essel Philippe
Published: September 2008

The drilling of hard formations usually requires specific drilling systems to achieve an efficient rate of penetration. Due to the limited depth of cut, the solution often involves the use of high RPM drive systems such as turbines or high speed motors and a fixed cutter product is usually the drill bit of choice.

With increasing well depth the roller cone option is normally avoided due to the low penetration rates and limited rotating hours obtainable with these drill bits. Roller cone use invariably leads to multiple trips and a significant increase in the time and cost of the drilling operation, especially for deeply buried reservoirs where hard rocks are generally encountered and bit diameter is reduced at TD.

Unavoidably, in some applications roller cone bits continue to be used in order to obtain the quality cuttings necessary for the geologist to correctly assess the formation. This is typically the case when the reservoir interval is encountered and exact formation knowledge is critical.

A new drilling solution has been developed to address this situation and is presented in this paper.

The idea consists of a fixed cutter bit which leaves the center of the hole uncut. The lack of bit center leads to the creation of a core. This core is broken by the bit itself and ejected at the side through a specifically designed junk slot. The core is then carried to the surface along with the other cuttings. This process leads to very high quality cuttings for surface examination.

The improvement is especially important where normal cuttings quality is poor due to the use of turbines or high speed motors together with impregnated diamond bits.

Importantly, as the center part of the bit is uncut this new technology also provides a significant increase in the rate of penetration. In a fixed cutter bit the center is one of the most inefficient cutting areas as the rotational speed of the cutter is low to null. By removing the center, an increased ROP efficiency in the range of 15 to 25 percent can be obtained depending upon the bit diameter.

The field tests that are presented in the paper show quantifiable improvements in terms of geological sample quality, cutting efficiency and drilling cost reduction.
A Guide to Successful Backreaming Real-Time Case Histories
Authors: Yarim Gokhan , Ritchie Graham Martin , May Richard B.
Published: September 2008

Backreaming is the practice of pumping and rotating the drillstring while simultaneously pulling out of the hole. When reliable top drive drilling systems (TDS) on conventional drilling rigs were introduced over 25 years ago, the practice of backreaming became a popular technique in the driller's toolbox for tripping out of hole initially in deviated wells.

In general, backreaming operations have become a popular solution to poor hole conditions while pulling out of hole, but they are also notorious for causing the very same problems they are supposed to prevent, such as stuck pipe. If backreaming is not done properly, it may complicate the operations, cause wellbore stability issues, higher ECDs, and it may also cause stuck pipe incidents due to packoffs.

As part of Integrated Project Management's (IPM's) stuck pipe prevention initiative, it became clear that when backreaming is carried out in a wellbore that has a large amount of cuttings and/or cavings, it can cause problems rather than solve them if it is not done with sufficient care. Also backreaming and tripping operations were usually occasions when the rig based team went to a "low vigilance" level. Based on historical cases, it was concluded that in the majority of instances there were no clear guidelines on when to start, how to do it, when to slow down, and when to stop backreaming operations. A review of industry literature also indicated a lack of procedures generally for backreaming.

As a result of the analysis of the real-time data from several case histories, a plan was put in place to improve backreaming operations, define the situations that require backreaming, and focus on tripping practices to prevent stuck pipe incidents and tool failures.

This paper focuses on one of the industry's most controversial subjects, reviews the implications of backreaming by using real-time data and case histories, and suggests proven procedures to trouble-free backreaming. It recommends the conditions that require backreaming and also suggests wellbore conditions that are not recommended for backreaming. More importantly, it proposes key drilling parameters that need to be monitored when backreaming. These include pump pressure, torque, hookload, cuttings rate and downhole measurements (if available) to detect and prevent backreaming induced operational problems. In addition, this paper provides guidelines for successful backreaming operations and defines conditions that may be resolved without needing to backream. Backreaming guidelines have been developed based on IPM company's world wide operations, supported by real-time case histories and extensive stuck pipe prevention program.

Introduction

Backreaming can be thought of as "drilling backwards" in order to trip out of the hole when there is a problem pulling the pipe out of the hole without rotation and circulation.