bluuebunny/crossref_metadata_2025 huggingface dataset:
Discretization, Simulation, and the Value of Information
Authors: Eric Bickel J..
Published: June 2014

Most decision analyses include continuous uncertainties (e.g., oil in place, oil price, or porosity). Analysts are frequently concerned with how to best structure, compute, and communicate decision models under these circumstances. While decision trees are well suited for discrete random variables with a few possibilities, they become unmanageable for a large number of outcomes. To address this concern, analysts frequently use discrete approximations such as Swanson's Mean. Previous work has quantified how well differing discretization methods match the moments (e.g., the mean and variance) of the underlying continuous distribution. More specifically, previous work has not included the decision context in which the discretizations are used. In this paper, we begin to address this gap by comparing different discretizations within the context of an information-gathering decision problem. We find that the best discretization is highly dependent on the decision context, which is difficult to specify in advance. In addition, we contrast the use of discrete approximations to Monte Carlo simulation.
Implementing Healthy Lifestyle To Sustain Productivity In Addressing Increasing Business Challenges
Authors: Sukardjo Wahono H. , Wisprayogie Wisprayogie
Published: June 2014

Imagine your happiness if your project can be completed timely or even faster at lower cost because your team productivity is kept at 100% or higher. This paper describes how Healthy Lifestyle behavior is consistently socialized and campaigned throughout organization to help maintaining employee’s productivity.

PT Chevron Pacific Indonesia, a Chevron oil exploration & production company in Sumatra, bring its thousands workers entering ‘a journey to a world class healthy lifestyle’ in late 2009. A series of health campaigns and health programs were conducted to bring employees and their families exercising healthy lifestyle behavior in their daily activities. It needs a paradigm shift from curative to preventive investment mode. Certainly, a cultural change and great support from all layers is becoming the key factor of the success of the program. All of those along with best practices and lessons learned will also be described in the paper.

Data statistics show that the patients visiting in-camp company hospital and clinics facilities are reducing from 185,000 visits in 2009 down to 172,000 visits in 2010. Assuming employee who visit clinic will spend his 1–1.5 hour of his productive time, then there is a significant opportunity of productive time can be saved if employees and their family members are stay healthy. As side financial benefit, this will help arresting the increase of company medical cost. Also, employee with healthy lifestyle behavior will harvest good health condition not only during employment but also after retire. In summary, healthy lifestyle will drive a healthy company, healthy retiree and happy family.
The Link Between Safety and Shift Handover
Authors: Brazier Andy , Sedgwick Martin
Published: June 2014

Health, safety and environment have always been important to the industry but recent events have brought them to the fore. Accidents such as Buncefiled, Texas City and the Gulf of Mexico spill are examples of how poor shift handover and lack of communication of operational information in particular can be a contributing factor to major incidents.

This paper will focus on the importance of effectively communication key operational data, from the control room through to senior management. It will examine the methods currently in place today for collecting and sharing this data and introduce the concept of electronic shift logging. It will look at real examples from other industries, e.g. Power Generation, of how it can minimize the likelihood of error in the high risk activity of shift handover, through improved communication and information management which in turn impacts safety and accident prevention.

This paper will demonstrate with case study example how new technologies can achieve this by replacing the myriad of paper logs, spreadsheets and disparate databases with a single electronic system designed to integrate information from many different sources in one location. This information can be used across the business to improve safety, reliability, production and environmental performance.

As Infotechnics have an established and successful track record of delivering operational logbook software to customers worldwide from the chemical and power industries as well as oil & gas, they are well positioned to offer knowledge and experience in this paper that will illustrate how the upstream industry can learn from other sectors.
A Comparison of Polymer Flooding With In-Depth Profile Modification
Authors: Seright Randall , Zhang Guoyin , Akanni Olatokunbo , Wang Dongmei
Published: June 2014

For stratified reservoirs with free crossflow and where fractures do not cause severe channeling, improved sweep is often needed after water breakthrough. For moderately viscous oils, polymer flooding is an option for this type of reservoir. However, in recent years, an in-depth profile-modification method has been commercialized in which a block is placed in the high-permeability zone(s). This sophisticated idea requires that (1) the blocking agent have a low viscosity (ideally a unit-mobility displacement) during placement, that (2) the rear of the blocking-agent bank in the high-permeability zone(s) outrun the front of the blocking-agent bank in adjacent less-permeable zones, and that (3) an effective block to flow form at the appropriate location in the high-permeability zone(s). Achieving these objectives is challenging but has been accomplished in at least one field test. This paper investigates when this in-depth profile-modification process is a superior choice over conventional polymer flooding.

Using simulation and analytical studies, we examined oil-recovery efficiency for the two processes as a function of (1) permeability contrast, (2) relative zone thickness, (3) oil viscosity, (4) polymer-solution viscosity, (5) polymer- or blocking-agent-bank size, and (6) relative costs for polymer vs. blocking agent. The results reveal that in-depth profile modification is most appropriate for high permeability contrasts (e.g., 10:1), high thickness ratios (e.g., less-permeable zones being 10 times thicker than high-permeability zones), and relatively low oil viscosities. Because of the high cost of the blocking agent relative to conventional polymers, economics favors small blocking-agent-bank sizes (e.g., 5% of the pore volume in the high-permeability layer). Even though short-term economics may favor in-depth profile modification, ultimate recovery may be considerably less than from a traditional polymer flood.
Effect of Dynamic Loading on Wellbore Leakage for the Wabamun Area CO2-Sequestration Project
Authors: Nygaard Runar , Salehi Saeed , Weideman Benjamin , Lavoie Robert Guy
Published: June 2014

The most viable options for permanent removal of carbon dioxide (CO2) from the atmosphere include large-scale injection of CO2 from stationary sources, such as coal-fired power plants and heavy-oil production, into brine-filled formations. One of the main risks identified with storing CO2 in the subsurface is the potential for leakage through existing wells penetrating the caprock. The wellbore system has several components that can fail and create leakage pathways, including type and placement of wellbore casing and cements, completion method, abandonment, and wellbore expansion or contraction by changes in temperature and pressure. Of the 1,000 wells in the study area near Wabamun Lake, Alberta, 95 wells penetrated the immediate caprock above the proposed Nisku injection formation and were identified as potential leakage pathways. The leakage risk of these wells was evaluated on the basis of knowledge of the well design, current well status, and historical regulations in the area. Only four wells, for the subset of 27 wells studied, were identified as requiring workover, which was less of a problem than anticipated. To evaluate the risk of creating leakage pathways by thermal and pressure changes caused by CO2 injection, a 3D finite-element model was built by use of poroelastoplastic material models for cement and formation. Multistage simulations for casing/cement and cement/ formation interactions with temperature-enabled elements were conducted. A parametric study of cement properties was conducted to investigate cement design and its mechanical properties for injection wells. The simulation results indicated that thermal cooling might reduce near-wellbore stresses, which would increase the risk of integrity loss in casing/cement and cement/formation. The parametric study revealed that the risk of debonding and tensile failure would increase with increasing Young’s modulus and Poisson’s ratio of the cement under dynamic-loading conditions. In addition, low mechanical cement strength would increase the risk of shear failure in the cement.
Performance of Vertical Transient Two-Phase Flow Models Applied to Liquid Loading in Gas Wells
Authors: Waltrich Paulo J. , Falcone Gioia , Barbosa Jader R.
Published: June 2014

Liquid loading in gas wells is triggered when the produced gas loses the ability to lift the co-produced liquids up the tubing. These co-produced liquids accumulate at the bottom of the wellbore, causing a higher back-pressure on the formation which reduces production from the reservoir, and may ultimately kill the well. As this phenomenon is transient in nature, it requires transient modeling for proper characterization of its associated flow features and prediction of future well performance. However, there is a lack of dedicated models that can mimic the transient behavior which is typical of liquid loading.

This paper describes the modeling effort carried out to investigate the liquid loading sequence in a synthetic gas well using a commercial package for transient multiphase flow modeling and two research codes (one for steady-state flow, and one for transient flow). The results of the simulations for the pressure gradient were compared against experimental data. The experimental runs were performed using a facility which has a transparent vertical test section of 43 m in length, and 0.04859 m ID. Air and water were used as working fluids.

The results highlighted the capabilities and limitations of these simulators when evaluating liquid loading in gas wells. While good agreement was observed among all three codes for the modeled pressure drop, considerable divergence was noted in terms of the recognized flow regimes and the modeled liquid holdup. According to the literature and field observations, liquid loading is fundamentally related to the transitions between flow regimes and the associated transient flow mechanisms; thus, miscalculating them would inevitably lead to an erroneous prediction of well performance.

Based on the results from the simulations, the potential effect of mis-modeling liquid loading on flow assurance and production optimization are investigated, and the need for further developments in transient multiphase modeling is discussed.
Interpreting Pressure and Flow Rate Data from Permanent Downhole Gauges Using Data Mining Approaches
Authors: Liu Yang , Horne Roland N.
Published: June 2014

The Permanent Downhole Gauge (PDG) is a promising tool for reservoir testing, but has yet to reach its full potential. Generally, conventional well testing methods are most able to utilize small sections of constant flow rate data. However, data mining, a newly developed technique in computer science, is a tool that can reveal the relationship among variables from large volumes of data. The application of data mining algorithms to synthetic and field data has been successful in extracting the reservoir model from variable flow rate and pressure transient data.

The application is conducted in two steps. As a first step, the pressure and flow rate data from the PDG are used to train a nonparametric data mining algorithm. The reservoir model is obtained implicitly in the form of polynomials in a highdimensional Hilbert space when the algorithm converges after being trained to the data. In the second step, a constant flow rate input is fed into the data mining algorithm. The data mining algorithm will make a pressure prediction subject to the input flow rate. As the data mining algorithm has already obtained the reservoir model, the pressure prediction is expected to be the reservoir response given the constant flow rate. Therefore, the proposed constant flow rate and the predicted pressure are the reservoir model underlying the variable PDG data.

Noisy synthetic data and the real field data were used to test this approach. The method was able to recover the reservoir model successfully. Even at the extreme cases when the flow rate data are very noisy and changing frequently, and in the absence of any shut-ins, the method was still able to extract the reservoir models.
A Systematic Study of Oil Recovery Mechanisms from a Fractured and Vuggy Carbonate Reservoir
Authors: Farhadinia M. A. , Chen P. , Delshad M. , Mohanty K. K. , Rodriguez F. G.
Published: June 2014

Oil recovery from mixed-wet fractured reservoirs are highly challenging due to complicated mechanisms involved in interactions between triple porosity fractures, vugs, and matrix rocks and reservoir fluids. An extensive laboratory program was undertaken to find suitable chemicals that reduce interfacial tension and change wettability in mixed wet carbonate rocks to enhance the rate of imbibition. The reservoir cores were used to test the effectiveness of the developed chemicals in static imbibition cells and coreflood experiments. Using an in-house simulator, we modeled the oil recovery processes and inferred the prevailing mechanisms and essential parameters that contribute to oil recovery. The simulator uses relative permeability and capillary pressure functions that depend on saturation, wettability, and trapping number. A stochastic permeability distribution was needed to match the coreflood results in the vuggy and heterogeneous core. Wettability alteration can contribute up to 10% additional oil recovery based on the sensitivity simulations of the coreflood. Wettability alteration from preferentially oil-wet condition to more water-wet condition is the most prevailing mechanism of oil recovery from disconnected vugs.
Business Risk Analysis Using Monte Carlo Simulation on Macro & Micro Economic Trends (A Case of Fabrication Yard) Economic Trends
Authors: Srivastava Pramendra
Published: June 2014

It has been a challenge for the Operations Managers to analyze the impact of tangible and intangible risks and raise alarms on running projects and/or adjudicate a clear Go or No Go decisions on various investment proposals. This paper presents an innovative probabilistic valuation technique using MS Excel Risksim tools for simulations, wherein, stochastic processof Markov Chain integrated with Monte Carlo Simulations is used in developing Cash flow statements. Simulations running 1000+ cases using randomly changing independent and linked dependant variables were created to discuss the Business Risks and Sensitivities of various Macro and Micro economic factors and their subsequent impact on IRR(s), and Share prices. This study is applicable for currently operating businesses, Greenfield investment decision and M&A candidate valuations.

The case of fabrication yards for construction of offshore structures and platforms is used for illustration, with focus on the financial risks of business operations. Like any other business, Fabrication yard business is also subject to market dynamics and uncertainties, namely, Steel prices, oil prices, coal prices, Market size, Market share, skilled and unskilled labor productivity, Tariffs and taxes, Lending rates, Forex rates, competition, Political risks and of course un-godly events, like tsunamis and Economic Crisis. Most of these factors can be assigned a probabilistic range of variations, while few others may be dependant on them, and indirectly affecting other measurable risk factors, such as Market Size itself. This paper, at the end, estimates P50, P75 and P90 probabilistic values of IRR_asset, IRR_equity and Share_Prices for each scenario, followed by analysis. The result is astounding not only in terms knowing what the real risk is, but also how much?
A New SAGD Well Pair Placement; a Field Case Review
Authors: Jorshari Kamran R. , O’Hara Brendan
Published: June 2014

Steam assisted gravity drainage (SAGD), a tertiary recovery method, has been consistently improved by experimenting with various solutions in both oil-sands and heavyoil fields in Canada. The SAGD process consists of two stacked horizontal wells and is proven technology in heavy-oil fields. Employing the same concept of gravity drainage, SAGD well placement convention has been revisited and challenged many times. Known to the industry, the X-SAGD and JAGD processes are two examples of fit-for-purpose well design and recovery schemes that require unique drilling practices. The Celtic pool, located in Lloydminster, Saskatchewan in Canada is an active Husky Energy Inc. thermal field that includes 21 SAGD well pairs. In this heavy-oil pool, one of the SAGD well pairs (I3/I4) experienced production downtime shortly after coming into service. Following numerous unsuccessful service jobs, several re-entry options were suggested to recover remaining reserves. These included sidetracking the I3 well, re-drilling a new well from the same pad location, or commencing a new well from a different surface location. These cases were ranked and in 2010, based on a drilling risk assessment, the new horizontal producer well (I3A) was drilled close to the existing well pair. The I3A well was placed counter-currently below the exisiting injector well (I4) and successfully set parallel to the abandoned Well I3. Steam conditioning was completed in the first quarter of 2011, and the new SAGD well pair (I3A/I4) has been successfully put on production.

The new well pair was positioned in the opposite direction of a conventional SAGD well pair placement. This paper presents the original I3/I4 pair performance, the challenges, result of re-drilling Well I3A, reservoir simulation study and recent field production of the I3A/I4 SAGD well pair.
Microbial-Enhanced Treatment of Oil Sludge From Oil-Production Plants Using Rhodococcus ruber Z25
Authors: Zheng Chenggang , Yu Li , Huang Lixin
Published: June 2014

Oil sludge is one of the most commonly encountered pollutants in oil-production companies and causes serious problems for the environment. In the present study, a novel microbial-enhanced oil-sludge treatment technology is discussed. The technology was able to achieve self-cycle operation by producing the biosurfactant by Rhodococcus ruber Z25 during the biodegradation process of the total petroleum hydrocarbon (TPH) and employing it for recovery of the oil sludge. The initial TPH and moisture content were 507 g/kg and 12%, respectively. After the crude/biosurfactant-suspension (CBS) treatment, only 31 g/kg of residual TPH remained in the oil sludge and the oil-recovery efficiency achieved 93.88%. The residual TPH was degraded further by cultivation of Rhodococcus ruber Z25, and a total of 1.27 g/L of biosurfactant was produced. The treated oil sludge contained 1.4 g/kg of residual TPH, and the system in the present study produced no additional pollutant to the environment.
Transient Pressure Analysis of a Horizontal Well With Multiple Inclined Hydraulic Fractures Using Type-Curve Matching
Authors: Al Rbeawi S. , Tiab D.
Published: June 2014

Horizontal wells with multiple hydraulic fractures have become a common occurrence in the oil and gas industry, especially in tight formations. Published models assume the hydraulic fractures are vertical and symmetric. However, recent studies have shown that fractures are asymmetric and inclined with respect to the vertical direction and the axis of the wellbore.

This paper introduces a new technique for interpreting the pressure behavior of a horizontal well with multiple hydraulic fractures. The hydraulic fractures in this model could be longitudinal or transverse, vertical or inclined, symmetrical or asymmetrical. The fractures are propagated in isotropic or anisotropic formations and are considered as having different dimensions and different spacing. This technique, based on pressure and pressure derivative concepts, can be used to calculate various reservoir parameters, including directional permeability, fracture length, skin factors, and angle of inclination. The study has shown that early radial flow might develop when the spacing between fractures is significantly long.

This paper also suggests new applications for the well test analysis in the hydraulically fractured reservoirs. These applications are focusing on: 1) Evaluating the performance of the fractures, 2) Determining whether one or more hydraulic fractures do not perform properly as designed (closed) and 3) Locating the malfunctioning fractures.

A type curve matching technique has been applied using the plots of the pressure and pressure derivative curves. A set of type curves, which will be included in the paper, have been generated for the inclined transverse and longitudinal hydraulic fractures associated to the horizontal wells with different inclination angles from the vertical direction. A step-by-step procedure for analyzing pressure tests using these type curves is also included in the paper for several numerical examples.
Using Business Planning Best Practices for Career Management and Better Career Decision Making
Authors: Craig DeAnn , Caligari Ruben , Judah Janeen , Hasheem Hosnia , Karim Rashida
Published: June 2014

A career can easily span forty to fifty years. Over that time span an engineer in the petroleum industry will earn several million dollars in income. According to the 2010 SPE Salary Survey, the mean salary for all respondents with 19 years experience was $139,194 with over a 5% salary increase from the prior year. Almost a third of respondents had a car allowance. On the front page of USA Today, May 24, 2011, the headline read "Petroleum engineering majors can grease skids." Further in the article, the projected salary for a petroleum engineering major over a 40-year career was $4.8 million! Associated with the revenue, there will be living expenses and capital investments for items such as house and these will also amount to several million dollars. Each of you will have to make decisions that will impact both revenue and expenses. Each of you is equivalent to a small business! How come more engineers don't make use of established business planning best practices to manage careers?

There are several things every engineer must remember. It is your career and, therefore, your responsibility to manage it. Each of you has the skill set learned through your university education or your industry experience to manage your career. This is a global, interconnected industry and your reputation will follow you from location-to-location and company-to-company. Finally, when you look back on your career, are you going to be happy with how you managed it?

This paper will provide an example of using business planning practices, including decision analysis, to manage a career. There are other ways to manage your career, including just letting it take its own course. Each person needs to determine what approach works best for her.
Self-Help and Leveraging Scale by Means of the Wells' Advanced Collaborative Environment's Global Community of Practice
Authors: Sawaryn S.J. J , Deady A , Lennox S , Moore-Cernoch K , Morrison J.M. M , Saunders M
Published: June 2014

The Advanced Collaborative Environment Community of Practice (CoP) was formed in March 2009 at the request of BP senior management to share good practice and promote standardization in the area of wells. Its mandate was one of self-help and leveraging scale but working through influence and consensus, with management support rather than by direct authority. The CoP was also required to adhere to company information technology (IT) standards and technology strategy.

At the time of the CoP's formation, collaborative environments had been commissioned in various company locations worldwide, including Aberdeen; Baku, Azerbaijan; Houston; Stavanger; and Tangguh, Indonesia. In the absence of standardized requirements for Wells’ collaborative environments and with an emphasis on innovation, each of these centers had been developed independently, strongly influenced by local ideas, needs, and resources. However, it was evident that connectivity between the different locations and with other disciplines was lacking, and that effort was duplicated.

The CoP currently has more than 30 members, including Wells, subsurface, IT, and well technology from 12 locations worldwide. It meets virtually, involving the widest possible membership in different time zones. It has been instrumental in progressing and communicating standards, supporting the introduction and use of common tools and technology, leveraging members’ knowledge and expertise, and helping startups in new areas. Overall, the CoP has been a great success. The paper describes the CoP's evolution, from its formation to the present, and critically examines its achievements, shortfalls, and future goals.

In a rapidly changing technical environment, achieving and maintaining alignment between the diverse stakeholders in a medium to large organization can be challenging. The CoP has earned its credibility and has proved to be an effective means of sharing experience and making good use of scarce resources, both keys for adoption at scale.
The Design of BHA and the Placement of the Magnetometer Sensors Influence How Magnetic Azimuth is Distorted by the Magnetic Properties of Drilling Fluids
Authors: Waag Tor Inge , Torkildsen Torgeir , Amundsen Per Amund , Nyrnes Erik , Saasen Arild
Published: June 2014

The magnetic property of the drilling fluid is one of the substantial error sources for the determination of magnetic azimuth for wellbores. Both the weight material, cuttings, clay and other formation material plus metal filings from the tubular wear may distort the magnetometer readings. This effect is obviously linked to the amount and kind of magnetic material in the drilling fluid, and the development of corrective means has therefore highlighted the drilling fluid. The problem has been studied by laboratory experiments and analyses of downhole survey data. However, there are several inconsistencies in the results, and the phenomenon is not fully understood. The geometric properties of the BHA and the magnetic directional tool are focused upon in this study.

The influence on directional MWD from drilling fluids has been studied using finite element modeling techniques. The simulations have been performed for several cases with realistic representations of MWD tool geometries and varying location of BHA versus the wellbore. One important result is that for situations with perfect axial symmetry, the magnetometer readings are attenuated proportionally to the square of the magnetic susceptibility. Since the magnetic susceptibility is a small number, this means that the effect on magnetometer readings is generally negligible. However, if the symmetry is broken, the distortion on the magnetometer readings can be increased significantly. This means that segregation of cuttings, metal filings or weight material can strongly influence the strength of the measured magnetic fields.

With a collar based tool, that is non-symmetric by nature, the model shows a complex distortion picture. The influence varies with the tool face angle, and shows both attenuation and amplification. The distortion maxima and minima for the two cross-sectional magnetometers do not coincide. These findings underline how hard it will be to find a straight-forward corrective action.

The results from the simulations give increased knowledge about the influence from the magnetic properties of the drilling fluid. This is essential for accuracy estimation and multistation analysis of magnetic survey data. Furthermore, the results demonstrate the importance of considering the geometry of the BHA and the tool, and of the sensor placement when performing the mechanical design.
A Sonic Method for Analyzing the Quality of Cementation of Borehole Casings
Authors: Grosmangin M. , Kokesh P.P. , Majani P.
Published: June 2014

Determination of the quality of cementation of casing in oil wells in the past has involved inflow and circulation tests to insure that the producing zones were adequately sealed off from the adjacent zones. Existing logging methods, such as temperature and radioactivity surveys, may detect the presence of cement behind the casing. However, the qualities of the cement (i.e., its hardness and particularly its bond to the casing) are not indicated.

The new logging method described in this paper operates on the principle that the attenuation of a sonic pulse transmitted by a casing is greatly increased when that casing is bonded to an outer annulus of hard material (such as set cement) which has an appreciably smaller sonicwave velocity than that of the casing.

The down-hole tool contains a source of recurrent sound pulses which are detected by a receiver spaced a few feet from the source The amplitude of the detected casingborne pulse is measured, and the resulting signal is transmitted to the surface where it is recorded vs depth. Since amplitude is a function of attenuation, the log is readily interpreted.

Laboratory studies have shown straightforward relationship between attenuation and such variables as source-detector spacing and per cent of circumference bonded. It is shown that cement not set or not bonded to the casing has comparatively little attenuating effect. Field examples show not only the cement top, but also the variation in cementation quality below the top. Further, the increase of bonding with time and after squeeze cementation is depicted. The detection of poor cement jobs is confirmed by production tests and by formation-test results.

It is anticipated that the method will have wide application in evaluating cementation quality prior to formation testing in completions and recompletions. The analysis it affords may aid in further improving cementation techniques.
Comprehensive Review of Damages and Repairs on Drill Pipe Connections
Authors: Redlinger Thomas M. , Griggs P. Steven , Odell Albert , Bergo Stein
Published: June 2014

In the last two decades the drilling industry has experienced major changes in both drillpipe connections and related inspection criteria. Many operators and contractors now regularly use premium drill pipe connections to drill all sections of their wells. One result of this is that the drilling community is often surprised by the amount of post-well drillpipe repairs that are required. There is little or no established statistical data available to budget repairs in any given well program. Instead they have been left to guess how much to budget into a given drilling project.

This paper will review data from two inspection databases containing in excess of 200,000 joints of drill pipe. The records were derived from operational data obtained from several years of drill pipe inspection. The databases contain inspection records for premium, double shoulder and API connections. The paper will discuss how different inspection standards, premium connections, etc. can affect the "damages" at the end of the drilling program. The objective of the paper is to provide planning factors to the drilling community in order to provide a basis for budgeting repair costs and to highlight the impact of connection selection and inspection standards on repairs.
Improved Compositions for Cementing Wells with Extreme Temperatures
Authors: Ostroot G. Warren , Walker Wayne A.
Published: June 2014

An increase in the number of deep wells being drilled where extreme bottom-hole temperatures are en countered, and the anticipated drilling of wells where temperatures in the range of 500°F or higher may occur, has brought about a comprehensive investigation of cementing materials and of the techniques involved in their proper usage at these elevated temperatures.

Included are developments in cements, retarders, weighting materials and other cement additives which make it possible to formulate a variety of compositions to help resolve the cementing problems of these extreme well conditions. The problems associated with the selection and testing of cements are discussed, and a resume of field results is included.

Previous studies on strength retrogression indicate that caution should be exercised in the selection of a cementing composition for use in high-temperature wells. It now appears that, by the addition of silica flour as a stabilizing additive to certain cements, compositions covering a wide range of slurry densities can be designed to meet extreme well conditions without strength retrogression.

Improvements in cement retarders make it possible to produce a four-hour thickening time at static temperatures up to 500°F. This temperature is considerably higher than conditions presently being encountered in drilling and completion work. Inert weighting materials, used to produce 20-lb/gal or heavier cement slurries, are reviewed.

Introduction

As the search for oil continues, the number of wells being drilled to depths of 10,000 ft or below has continued to increase over the past decade. During 1959, there were 50,893 wells drilled in the United States for a total of 209 million ft of hole. Of this total, approximately 4.45 per cent were drilled below 10,000 ft and 0.30 per cent below 15,000 ft, with a record depth of 25,340 ft recorded (Table 1).

With the drilling of this record-shattering hole comes the question, "How deep can wells be drilled?" Limitations with respect to equipment (surface and subsurface), cementing materials and techniques would cause some concern; however, a panel of experts have agreed that the U.S. oil industry has the equipment and know-how to drill a 50,000-ft hole. The greatest deterrent would be the 700°F temperature they would anticipate encountering at this depth.
High-Confidence Vertical Positioning for Extended Reach Wells
Authors: Mohammed Nelson , Terpening Michael
Published: June 2014

Establishing confidence in the vertical thickness of the hydrocarbon column (HC) is a critical driver in development project economics. True vertical depth (TVD) uncertainty associated with the HC, in the absence of vertical appraisal well data, may be dominated by the propagation of inclination error in non-vertical or horizontal pilot wells. The challenges associated with establishing reliable hydrocarbon column height can be extreme if high-stepout extended reach (ER) wells are the primary source of appraisal data. Moreover, thin reservoirs targeted by ER wells often have a limited vertical "driller’s target" based on standard TVD error propagation models.

Historically, TVD error improvements over current industry standards have been difficult to document reliably for various reasons: down-hole equipment limitations, bandwidth constraints on measurement-while-drilling (MWD) data, sparse data sets with limited resolution, accounting for variable bottomhole assembly (BHA) geometries, changing borehole environment with time, and little scope for independent validation in a field environment.

This paper outlines the integration of three complementary elements to significantly improve on the TVD uncertainty associated with ER well paths and demonstrates the application in a field setting. The methodology leverages the capabilities of an advanced system incorporating MWD tools and a rotary steerable system (RSS) in combination with a high-quality, dynamically updated borehole sag-correction model to account for axial misalignment of the inclination sensors within the wellbore. Results were corroborated initially with independent third-party surveys and validated with a high-quality formation pressure while drilling (FPWD) data-set from seven ER wells drilled in a hydraulically continuous reservoir prior to production.

The approach was successful in defining the primary HC to an exceptional degree of accuracy from a combination of gas and fluid gradient data in two separate ER pilot holes, enabling proper vertical placement of the production hole in the reservoir. The uncertainty associated with the pressure gradient in a secondary (hydraulically distinct) reservoir was also significantly improved based on the implied vertical offsets from the established reference gradient in the primary reservoir.

The general applicability and real-time capability has been tested under demanding operational conditions on a more recently drilled ER well in the same field, demonstrating the robustness of a TVD assurance methodology that significantly improves the risk-profiles of ER projects for asset management teams.
Drilling Automation: Potential for Human Error
Authors: Iversen Fionn , Gressgård Leif Jarle , Thorogood John L. , Balov Mohsen Karimi , Hepsø Vidar
Published: June 2014

Mode confusion is an automated system behaving differently than expected and the operator not being aware of (or not properly understanding) what the system is doing. Mode confusion is well-recognized in the aviation community and has been indicated in a number of high-profile aviation accidents. As an example, a JAS Gripen fighter jet crashed during a test flight in the 1980s because the pilot tried to manually correct instability while the plane's computer was automatically trying to do the same. The potential for the same type of problems, and associated safety hazards, arises in drilling-rig operations as a result of the increasing trend for automation and advisory systems. A simple example could be formation fracturing with an automated downhole pressure-control system when displacing to higher mud weight caused by the driller relying on the automated system to maintain sufficiently low flow rate without having reconfigured the system with the new mud properties. This paper describes how the use of a drilling support system in different modes and levels of automation may influence the system operator's performance and risk of human error. The development of a systematic method for detecting mode-confusion problems by model checking is central in this respect. The test cases have been simulated in a virtual test environment created at IRIS specifically for such purposes. The test environment and test cases are described, and results are reported and discussed.
A New Approach in Permeability and Hydraulic Flow Unit Determination
Authors: Izadi Mohammad , Ghalambor Ali
Published: June 2014

Building an integrated subsurface model is one of the main goals of major oil and gas operators to guide the field development plans. All field data acquisitions from seismic, well logging, production and geomechanical monitoring to enhanced oil recovery operations can be affected by the accurate details incorporated in the subsurface model. Therefore, building a realistic integrated subsurface model in advance of the field development and associated design and operations is essential for a successful implementation of such projects. Furthermore, utilizing a more reliable model can in-turn provide the basis in the decision making process for control and remediation of formation damage.

One of the key identifier of the subsurface model is accurately predicting the hydraulic flow units. There are several models currently used in the prediction of these units based on the type of the data available. The predictions using these models are differing significantly due to the assumptions made in the derivations. Most of these assumptions do not adequately reflect realistic subsurface conditions increasing the need for better models to enhance the predictions.

A new approach has been developed in this study for predicting the petrophysical properties improving the reservoir characterization. Poiseuille flow equation and Darcy equation were coupled taking into consideration the irreducible water saturation in the pore network. The porous media was introduced as a domain containing bundle of tortuous capillary tubes with irreducible water lining the pore wall. A series of routine and special core analysis were performed on 17 Berea sandstone samples and the petrophysical properties were measured and XRD analysis was conducted. In addition, core permeabilities were predicted using a new permeability model and the results were compared to the measured permeability data. In building the petrophysical model, it was initially necessary to assume an ideal reservoir with 17 different layers. Afterwards, by iteration and calibration of the laboratory data, the more realistic number of hydraulic flow units was determined accordingly.

The same model was also implemented to a Cotton Valley tight gas reservoir in Northern Louisiana in order to determine the flow units. A comparative study shows that the new model provides a better distribution of hydraulic flow unitsand prediction of the petrophysical properties. Using the new model provides a better match with the experimental data collected than the models currently used in the prediction of such parameters. The good agreement observed for both the Berea sandstone and Cotton Valley tight gas sand experimental data and the model predictions using the new permeability model show the wider range of applicability for various reservoir conditions.
Taking Advantage of Fines Migration Formation Damage for Enhanced Gas Recovery
Authors: Nguyen P. T. , Zeinijahromi A. , Bedrikovetsky P.
Published: June 2014

The core permeability decline during corefloods with varying water composition, especially with low salinity water, has been widely reported in the literature. It has often been explained by the lifting, migration and subsequent plugging of pore throats by fine particles, which has been observed in numerous coreflood tests with altered water composition. In this work, the concept of using this permeability decline in order to decrease water production during pressuredepletion in gas field is investigated. The small volume injection of fresh water into an abandoned watered-up well in order to slow down the encroaching aquifer water is discussed. Equations for two-phase immiscible compressible flow with fines migration and capture have been derived. In large scale approximation, the equations are transformed to the black-oil polymer flooding model. The performed reservoir simulation shows that injection of fresh water bank significantly decreases water production and improves gas recovery.
Measuring Capillary Pressure Tells More Than Pretty Pictures
Authors: Pagels Markus , Hinkel Jerald J. , Willberg Dean M.
Published: June 2014

Exploitation of shale reserves requires injection of large quantities of water-based fluids during hydraulic fracturing treatments. Damage to the fracture conductivity and to the near-fracture matrix permeability caused by residual water can be avoided by optimizing fracture cleanup. The wide variation in mineralogy, texture and lithology of kerogen rich shales entails a substantial variation in the wetting characteristics of these rocks on all scales, whether one is comparing rock from different reservoirs, formations, or even different zones within a formation. It is therefore critical to evaluate shale/fluid interactions. The contact angle is a quantitative measure of the relative wettability of a substrate with respect to two fluids brought into contact with it. To understand dynamic processes in the reservoir, dynamic contact angles need to be measured. Dynamic contact angles (advancing/imbibing and receding/draining fluids) differ substantially from static contact angles. For fracture cleanup the receding contact angle is most relevant. Obviously, static goniometer measurements that are presently used in the industry to infer fluid behavior within the rock matrix give wrong results that do not reflect the mixed wettability of shales with diverse pore types. The results of a macroscopic goniometer measurement, obtained on a polished surface cannot be projected down to pore scale with rough and diverse surfaces.

In this document, we present a rapid and practical method to measure the saturation dependent capillary pressure in a shale sample pack. A new method has been developed to measure threshold pressures and receding contact angles on freshly prepared shale and mudstone surfaces. We introduce a fluid retention ratio as a meaningful way to directly compare additive performance with regards to fracture cleanup.

This method is used to screen treatment fluid additives on a reasonably small amount of formation material. Rock samples from different shale formations have been tested with various additives. Measurement results show that different additives behave differently when exposed to shales from different reservoirs; different responses are even observed from well to well in the same reservoir and zone to zone in the same well.
Productivity Impairment of Gas Wells Due to Fines Migration
Authors: Zeinijahromi A. , Vaz A. , Bedrikovetsky P.
Published: June 2014

Well productivity decline have been widely observed for gas wells producing the reservoir fines. The phenomenon has been explained by the lifting, migration and subsequent plugging of the pores by the fine particles, finally resulting in permeability decrease. It has been observed in numerous core flood tests and field cases. The new basic equations for the detachment of fine particles, their migration and size exclusion, causing the rock permeability decline during gas production, have been derived. The analytical model, developed for the regime of steady state gas production with a gradual accumulation of strained particles, exhibits the linear skin factor growth vs the amount of produced reservoir fines. The modeling results are in a good agreement with the well production history. The model predicts well productivity decline due to fines production based on the short term production data.
Aluminum and Iron Precipitation During Sandstone Acidizing Using Organic-HF Acids
Authors: Al-Harbi B. G. , Al-Dahlan M. N. , Al-Khaldi M. H.
Published: June 2014

Different organic-HF acid mixtures have been used to stimulate sandstone formations. Typically, they are used as alternative to regular mud acid in order to overcome its potential limitations such as rapid spending, high corrosion rate and incompatibility with sensitive clays. However, organic-HF systems are more susceptible to fluoride-based precipitations because they contain high amount of free fluoride ions. This paper focuses on identifying the type of precipitations that occur during reactions of organic-HF acids, and on determining the factors that affect these precipitations.

Solutions of different organic-HF acids namely formic, acetic and citric acid, containing HF concentrations of 0.5, 1 and 1.5 wt%, were examined in this study. Aluminum chloride or iron chloride were added separately to each organic-HF acid solution to contain 1,000; 5,000 or 10,000 mg/L of aluminum or iron (III) ions, respectively. The acid mixtures were neutralized by adding sodium hydroxide. Filtered solutions were analyzed using inductively coupled plasma (ICP) to assess the ability of used acids to hold Al and Fe (III) dissolved ions, while formed solid precipitates were analyzed by X-ray diffraction (XRD).

The type and amount of precipitates were found to be mainly dependent on solution pH, organic-HF type, and initial free fluoride concentration. All live organic-HF acids containing dissolved iron (III) showed no precipitation even after iron (III) level reached 10,000 mg/L. However, when solution pH value was raised, none of tested organic-HF acids were able to prevent iron fluoride precipitation. On the other hand, the main factor that controlled the aluminum-fluoride precipitation was found to be F/Al ratio. It was found that there is a critical F/Al ratio, above which the aluminum fluoride precipitation occurred.