Kick-off Point Research Articles

Revisiting Calls to Restructure Nigerian Styled Federalism

Over-dependence by federating units on the central government on financial matters, created some misgivings over the operational trajectory of federalism and its acclaimed dysfunctionality in Nigeria. The paper revisits the calls to restructure Nigeria's peculiar federalism, evaluates the historical antecedents, assessed government's response to such calls, at the same time, examines altercations for and against restructuring. It adopted political economy for theoretical framework, and descriptive research design, utilising secondary source of data with content analysis. The paper found that the main bone of contention is anchored around economic exclusivity by the federal government, which is breeding dissatisfaction. Nature of politics influenced lopsided restructuring that concentrated on territorial aspects, rather than the economic domain, this disabled fiscal federalism. It concluded that the policy of concentrating revenue allocation at the centre, does not give room for each federating unit to leverage on their capacity to internally generate revenue from the resources in their environment. In order to enjoy the dividend of federalism, and advance towards achieving sustainable development a revisit to calls for restructuring is needed. There is fluidity in government's commitment toward restructuring, seen in the lack of implementation of various committees reports on restructuring and fiscal federalism. Also, there is absence of the political will to change the status quo of unitarized federalism. The paper recommends that comprehensive restructuring, with the states and local government revenue generating capacity as the kick-off point. It urgently requires cutting down cost of governance to the barest minimum.

Optimizing geological design of J-shaped deviation oil & gas well by deepening kickoff point

In the geological design of 2-D J-shaped deviated oil and gas wells, once the coordinates of wellhead and production layer target are determined (restricted by specific ground conditions and underground understanding, respectively), the position of the kickoff point (KOP) becomes very sensitive. By deepening the kickoff point (KOP) based on the current conventional fixed upper position and the dog leg severity (DLS) remaining unchanged within the penetrated range, a smaller drill axis and an angle between the production layer and axis can be obtained at the same designated target point to extend the section of penetrated oil-bearing layers, expand the oil drainage area, increase proven reserves, and ultimately enhance the oil production and recovery during the contract period. In addition, after optimization, it is expected to save 1-2% of well drilling costs by reducing drilling time. With the help of drilling engineering and production engineering, drilling KOP can be achieved easily in deeper and harder rock formations, which is able to improve the efficiency of the electric submersible pump (ESP) and to avoid eccentric wear of the ESP, resulting in extension of the service life of the ESP. This optimized design also runs in parallel with various well stimulation programs and projects without any confliction of each other. This design can be either used for comparison of the parameters of the completed inclined wells with assumed ones of deepening KOP design to show how the deepening KOP can be used to differentiate the increased thickness of the penetrated target layers and the drainage area of target zones, or it can be utilized to compare any pair of parameters between inclined production wells within a range. In the same drilling field, any random increase of 1° inclination angle in a stable inclination section can lead to a corresponding increase in the thickness of the penetrated oil-bearing layer and production. Our research results quantitatively indicate that in the geological design of J-shaped deviation oil and gas wells, the KOP can be re-set from a shallower fixed position along the current conventional trajectory to a reasonable position as deep as possible, which shall be suitable for most situations of optimizing well performance, especially for some restricted complex surface conditions and energy-deficient reservoirs, which assign the KOP a new geological significance in line with the business strategy of rapid oil recovery

Lateral bearing characteristics of subsea wellhead assembly in the hydrate trial production engineering

Conductor and suction anchor are the key equipment providing bearing capacity in the field of deep-water drilling or offshore engineering, which have the advantages of high operation efficiency and short construction period. In order to drill a horizontal well in the shallow hydrate reservoir in the deep water, the suction anchor wellhead assembly is employed to undertake the main vertical bearing capacity in the second round of hydrate trial production project, so as to reduce the conductor running depth and heighten the kick-off point position. However, the deformation law of the deep-water suction anchor wellhead assembly under the moving load of the riser is not clear, and it is necessary to understand the lateral bearing characteristics to guide the design of its structural scheme. Based on 3D solid finite element method, the solid finite element model of the suction anchor wellhead assembly is established. In the model, the seabed soil is divided into seven layers, the contact between the wellhead assembly and the soil is simulated, and the vertical load and bending moment are applied to the wellhead node to simulate the riser movement when working in the deep water. The lateral bearing stability of conventional wellhead assembly and suction anchor wellhead assembly under the influence of wellhead load is discussed. The analysis results show that the bending moment is the main factor affecting the lateral deformation of the wellhead string; the anti-bending performance from increasing the outer conductor diameter is better than that from increasing the conductor wall thickness; for the subsea wellhead, the suction anchor obviously improves the lateral bearing capacity and reduces the lateral deformation. The conduct of the suction anchor wellhead assembly still needs to be lowered to a certain depth that below the maximum disturbed depth to ensure the lateral bearing stability, Thus, a method for the minimum conductor running depth for the suction anchor wellhead assembly is developed. The field implementations show that compared with the first round of hydrate trial production project, the conductor running depth is increased by 9.42 m, and there is no risk of wellhead overturning during the trial production. The method for determining the minimum conductor running depth in this paper is feasible and will still play an important role in the subsequent hydrate exploration and development.

Untargeted-based metabolomics analysis and in vitro/in silico antiviral activity of extracts from Phyllanthus brasiliensis (Aubl.) Poir.

This study describes the molecular profile and the potential antiviral activity of extracts from Phyllanthus brasiliensis, a plant widely found in the Brazilian Amazon. The research aims to shed light on the potential use of this species as a natural antiviral agent. The extracts were analysed using liquid chromatography-mass spectrometry (LC-MS) system, a potent analytical technique to discover drug candidates. In the meantime, in vitro antiviral assays were performed against Mayaro, Oropouche, Chikungunya, and Zika viruses. In addition, the antiviral activity of annotated compounds was predicted by in silico methods. Overall, 44 compounds were annotated in this study. The results revealed that P. brasiliensis has a high content of fatty acids, flavones, flavan-3-ols, and lignans. Furthermore, in vitro assays revealed potent antiviral activity against different arboviruses, especially lignan-rich extracts against Zika virus (ZIKV), as follows: methanolic extract from bark (MEB) [effective concentration for 50% of the cells (EC50 ) = 0.80 μg/mL, selectivity index (SI) = 377.59], methanolic extract from the leaf (MEL) (EC50 = 0.84 μg/mL, SI = 297.62), and hydroalcoholic extract from the leaf (HEL) (EC50 = 1.36 μg/mL, SI = 735.29). These results were supported by interesting in silico prediction, where tuberculatin (a lignan) showed a high antiviral activity score. Phyllanthus brasiliensis extracts contain metabolites that could be a new kick-off point for the discovery of candidates for antiviral drug development, with lignans becoming a promising trend for further virology research.

Understanding seller resistance to digital device recycling platform: An innovation resistance perspective

• Attracting recyclers is vital to the success of digital device recycling platform (DDRP). • This study employs innovation resistance theory as the theoretical paradigm. • This study reveals that perceived security and privacy risk, attitudes toward sustainability, and negative word-of-mouth have significant impact on seller resistance to DDRP. • These findings serve as a kickoff point for researchers to interpret user’s intention to use DDRP. In the resale commerce (reCommerce) movement, the digital device recycling platform (DDRP), which allows users to sell, trade-in, and recycle used digital devices online, is growing in popularity and significance globally. Although DDRPs offer new opportunities for commerce and sustainability, challenges exist to support wide adoption. This study attempts to develop a deeper understanding of the reasons underlying seller resistance to the DDRP. Grounded in the innovation resistance theory (IRT), the research model of this study is validated using data collected from 307 Chinese potential sellers of used digital devices. Using the structural equation modeling techniques, this study reveals that perceived security and privacy risk, attitudes toward sustainability, and negative word-of-mouth have a significant impact on seller resistance to DDRP. Finally, the control variable, education, negatively affects seller resistance. These findings not only offer important theoretical contributions to green IT research but also provide guidance to DDRP operators for formulating strategies to reduce seller resistance.

Implementing the autonomous adaptive algorithm to manage ESP operation in harsh reservoir conditions

The well geometries with a shallow kick-off point in conjunction with surface infrastructure limitations have led to Electrical Submersible Pump (ESP) technologies' application as one of the most suitable artificial lift methods for the harsh reservoir conditions. However, the harsh reservoir conditions in terms of the low reservoir pressure, high reservoir temperature, scaling problems in various forms, and high gas content at the pump intake have reduced the ESP system run life. Therefore, this research represents the Autonomous Adaptive Algorithm (A3) as a holistic approach to integrate analytical and machine learning models to assist production engineers in the early detection of operating problems. The A3 relies on different data sources and uses unique, well diagnostics logic to generate valuable features and prepare data for training. Finally, the paper evaluates different classifiers and explores the possibilities of application A3 as a flexible edge solution. The research benefits will be demonstrated for several problematic ESP wells.

Vector-based three-dimensional (3D) well-path optimization assisted by geological modelling and borehole-log extraction

This paper describes a novel strategy to optimize the drilling time of three-dimensional (3D) directional wellbore trajectories using a vector-based approach subject to drilling and geological constraints. Many existing well-path models require manual entry for certain geological constraints such as formation dip or kick-off limit. In contrast, this vector-based approach ensures that geological constraints are automatically satisfied by building a geological model, and extracting a borehole log of key points along the well-path. The presented approach applies and compares a deterministic optimization technique known as Constrained Optimization by Linear Approximation (COBYLA) with a Genetic-Algorithm (GA) global optimization to determine the optimum 3D well path to drill the target. While optimizing the path, the model determines the optimum kick-off point based on the subsurface-formation strength and depth subject to predetermined doglog severity, inclination and azimuth angles. The methodology is applied to well paths with different number of build-up and drop sections in unconstrained and constrained geological settings. Results show that COBYLA and GA are comparable when not using geological modelling while GA is superior for complex well-path geology-assisted optimization problems. The technique is applicable for a single well path planning, and can be expanded to a set of wells being optimized during Field Development Planning (FDP).

“A multi-tier sustainable food supplier selection model under uncertainty”

Supplier selection in food supply chains (FSCs) is not much explored due to the inherent difficulties, complexities and nature of food industry. Food security and quality are top row topics in today’s world health scenario. During sudden food crisis, it needs extra attention where producers, suppliers, and stakeholders play the most vital roles. This paper puts forward a two-phase sustainable multi-tier supplier selection model for FSC based on an integrated decision analysis under multi-criteria perspectives considering sustainability criteria, suppliers and sub-suppliers. In the first phase, the model estimates supplier selection criteria weights using a combined version of step-wise weight assessment ratio analysis (SWARA) and level based weight assessment (LBWA) in conjunction with D-numbers. In the second phase, Measurement of Alternatives and Ranking according to the COmpromise Solution (MARCOS)-D method is applied to obtain a ranking pre-order of different tier suppliers. Moreover, several sensitivity analyses are carried out in order to examine model reliability. To check application practicability, the proposed model is implemented in a case study of WineSol Corporation in Spain. The proposed model is expected to serve as a kickoff point for developing advanced decision-making models for effectually address multi-tier supplier selection problems under uncertain environment.

Machine learning assisted detection of excess water-producing wells in unconventional shale plays

Excess water production from oil/gas wells drilled in unconventional shale formations of Permian Basin leads to environmental concerns related to the disposal of produced water and also leads to significant expenses in water management programs. In the Delaware Basin, water-to-oil ratios are as high as 10:1 for an oil-producing well. This paper analyzes subsurface data from 20 wells targeting the Bone Springs sands and the Wolfcamp shale formation, which are the primary unconventional-resource targets in the Delaware Basin. The dataset was expanded by adding 53 wells from both the Fort Worth Basin and Gulf Coast Region. For purposes of this study, a data-driven workflow was developed to use 5 well logs from the 300-feet depth interval above or below the kick-off point for each well to detect high water-producing well. The 300 ft of logged data above or below the KOP are divided into six 50-ft intervals. From these banded intervals, 7 statistical parameters were computed for each of the 5 logs. In doing so, 210 features were generated for each well, which were then reduced to most informative 21 features by first thresholding based on p-value and F value, followed by the use of Pearson Correlation. The dimensionally reduced 21 features were used to train classification methods to predict whether a well is a high-water producer (HWPs) and low-water producer (LWPs). Logistic regression performs the best. In Delaware Basin, the prediction performance has a median F1 score of 0.96 and a median Matthew's Correlation Coefficient of 0.92. Median scores for both the Fort Worth and Gulf Coast datasets are above 0.80. For the Delaware Basin, the statistical parameters computed using deep resistivity and porosity logs from the nearest 50-ft band just below the KOP are the most informative features for detecting excess water-producing well.

Optimization of Deviated and Horizontal Wells Trajectories and Profiles in Rumaila Oilfield

Directional and horizontal wellbore profiles and optimization of trajectory to minimizeborehole problems are considered the most important part in well planning and design. Thisstudy introduces four types of directional and horizontal wells trajectory plans for Rumailaoilfield by selecting the suitable kick off point (KOP), build section, drop section andhorizontal profile. In addition to the optimized inclination and orientation which wasselected based on Rumaila oilfield geomechanics and wellbore stability analysis so that theoptimum trajectory could be drilled with minimum wellbore instability problems. The fourrecommended types of deviated wellbore trajectories include: Type I (also called Build andHold Trajectory or L shape) which target shallow to medium reservoirs with lowinclination (20o) and less than 500m step out, Type II (S shape) that can be used topenetrate far off reservoir vertically, Type III (also called Deep Kick off wells or J shape)these wells are similar to the L shape profile except the kickoff point is at a deeper depth,and design to reach far-off targets (>500m step out) with more than 30o inclination, andfinally Type IV (horizontal) that penetrates the reservoir horizontally at 90o. The study alsorecommended the suitable drilling mud density that can control wellbore failure for the fourtypes of wellbore trajectory.

Optimization of drilling parameters for extended reach directional wells with an early kick-off point

This article analyzes the impact of an actual trajectory of a J-Type directional well with an early kick-off point on the values of torque and drag along the bore hole.The actual data collected while drilling the directional SU-2 well with a target depth of 5000 m (South Urikhtau field) was used for the analysis: trajectory survey data results of the well, actual bottom hole assemblies applied (dimensions, material and characteristics of the elements), the actual drilling mud parameters according the control acts, actual drilling parameters according the daily drilling reports and mud logging curves, etc.Calculations of torque and drag were performed on a specialized software Landmark, a comparative analysis was carried out with the design values of parameters and appropriate recommendations were issued.

Study Evaluates Ability of Tailpipe Systems To Optimize Artificial Lift in Horizontal Wells

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190938, “Evaluating Tailpipe Systems Designed To Optimize Artificial Lift Performance in Horizontal Wells,” by C.R. Humphreys, SPE, B.N. Vangolen, SPE, A.P. Allison, SPE, D. Yin, SPE, and C. Yicon, SPE, Occidental Petroleum, prepared for the 2018 SPE Artificial Lift Conference and Exhibition–Americas held in The Woodlands, Texas, USA, 28–30 August. The paper has not been peer reviewed. The performance of artificial-lift systems on horizontal wells is greatly influenced by both the volume of gas produced and the tendency for gas slugging. With a sucker rod pump (SRP) system, gas slugging leads to gas interference at the pump, reducing system efficiency and equipment run life. With an electrical submersible pump (ESP), gas slugs can cause cycling of the ESP, which may shorten run life significantly. A trial project was launched to evaluate the performance of two tailpipe systems that could be applied to both forms of artificial lift. Introduction The two tailpipe systems were tested in a number of wells using SRPs, and one well was tested using an ESP. The goal was to Reduce the frequency and magnitude of slugging behavior seen at the pump Reduce the flowing bottomhole pressure without having to land pumps past the kickoff point (KOP) Improve separation of free gas from the produced fluid before it reaches the pump intake The two systems differ in both separator design and packer location. The first uses a conventional packer-style gas separator with a reduced-inner-diameter (ID) tailpipe extending below the separator and past the KOP. The second uses a special cyclonic separator with a reduced-ID tailpipe, and the packer is located at the lower end of the tailpipe. The authors examined the differences between the two systems regarding the isolation location, whether at the top or bottom of the tailpipe, to aid in designing future systems. A comparison of the two separators was attempted, and various operational challenges are discussed in the complete paper to improve the design, installation, startup, and operation of these systems. Some installations were outfitted with downhole gauges (DHGs) measuring pressure and temperature at several points along the tailpipe. The DHGs recorded pressure at the tailpipe inlet and outlet, pump intake pressure, and pump discharge pressure. This surveillance package allowed for real-time monitoring of the performance of both the tailpipe and the artificial-lift system while also providing data for modeling the flow regime through the tailpipe. The modeling results were used to forecast long-term performance of the system as well production declines over time. Results from the field trial show the performance of each system from a variety of standpoints: changes in flowing bottomhole pressure, flowing behavior through the tailpipe, separation effectiveness, and changes in production.

Method for Designing the Optimal Trajectory for Drilling a Horizontal Well, Based on Particle Swarm Optimization (PSO) and Analytic Hierarchy Process (AHP)

In horizontal well drilling, the success of the drilling operation mainly depends on optimal selection of the drilling trajectory. In this paper-, we propose a method for optimizing horizontal well trajectory design based on the numerical optimization methods PSO (particle swarm optimization) and AHP (analytic hierarchy process). We selected four functions as the parameters which affect the selection of the optimal solution: the shortest length of the well trajectory, the highest target hitting accuracy, the lowest cost of drilling, and the least drilling string friction. The key parameters for a horizontal well (the KOP (kick-off point), BUR (buildup rate), and hold angle) were calculated by ththe PSO method in Matlab. Applying the AHP mathematical tool for a systematic approach to decision-making, we ranked the solutions according to the engineering and design requirements. The new method proposed in this paper lets us overcome the limitations of the optimization algorithm and to recast empirical judgments of experienced analyzers in mathematical language, thus avoiding subjectivity in selecting the best solution. The method was applied to and tested on conditions of the Yanchang field. As shown by the experimental study, the proposed method is a simple and reliable method for selecting the optimal trajectory.

Optimization Work Flow Converts Power to Performance for GOM Drilling

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29065, “Converting Power to Performance: Gulf of Mexico Examples of an Optimization Work Flow for Bit Selection, Drilling-System Design, and Operation,” by Mark W. Dykstra, SPE, Miguel A. Armenta, SPE, Fitzerald A. Mathew Ain, SPE, Omolara Adesokan, and Tess L. Schornick, Shell, and Ashabikash Roy Chowdhury, SPE, and Mark D. Allain, Baker Hughes, a GE company, prepared for the 2018 Offshore Technology Conference, Houston, 30 April–3 May. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. Time spent on bottom drilling is only approximately 10% of the time consumed by drilling operations, but this still provides a significant opportunity for savings if it can be reduced. The goal of the work described in this paper was to decrease this percentage while drilling an exploratory well in the Gulf of Mexico. Significant results were achieved with the use of advanced hybrid polycrystalline-diamond-compact/tungsten-carbide-insert (PDC/TCI) bits. Introduction The focus well is in the Walker Ridge area approximately 150 nautical miles south of Port Fourchon, Louisiana. The rig floor to the zone of interest includes 6,500 ft of water, 1,200 ft of sediments, 12,250 ft of salt, and then deeper sediments. In the basic well design, a 38-in. conductor would be jetted to 200 ft below the mudline. The 26-in. section would be drilled through sediments and 2,000 ft of salt without risers using seawater and a 9.3-lbm/gal water-based pump-and-dump (PAD) drilling fluid, after which the 22-in. casing would be set. The 16½-in. section would be drilled through the bulk of the remaining salt with a riser in place using synthetic-based drilling fluid. The well would remain vertical until the kickoff point. After setting a 14-in. casing, the remaining hole sections would exit the salt and penetrate the deeper zones using synthetic-based drilling fluid. Design Phase: Offset Well Study The first step in the optimization process was to evaluate the drilling challenges that could be encountered in each hole section and identify potential performance limiters. The key lessons from the analysis of offset wells include the following: The shale/sand sequence above the salt would be soft and could be drilled as quickly as desired, though subject to wellbore stability and hole-cleaning limitations. The salt section would be very drillable, but mechanical specific energy (MSE) levels would be approximately 40 ksi. PDC bits would be very aggressive, so torque would be highly sensitive to weight on bit (WOB). Peak rate of penetration (ROP) in both salt and sediments would be directly proportional to the power provided to the bit. Torque variation could be as low as 10 to 20% for stiff drillstrings featuring 65/8-in. drillpipe using relatively high rotary speeds (e.g., 170 rev/min or greater). Bottomhole assembly (BHA) designs with a minimal tendency to hang up are desirable.

Time-tracking tests and interpretation for a horizontal well at different wellbore positions

We have developed a time-tracking test method for pressure buildup tests of horizontal wells to reduce the costs associated with testing wells. The time-tracking test method requires several tests that are performed chronologically from the midsection of the horizontal wellbore to the kickoff point. The purpose of time-tracking tests is to determine the production conditions of horizontal wells that allow the tests to be conducted at the kickoff point. Two horizontal wells associated within a sandstone oil reservoir were specifically chosen to determine how our time-tracking test method is to be implemented. The two wells had completely different production conditions. One had a small gas rate and a large water cut, whereas the other had a large gas rate and a small water cut. We recorded and analyzed the tested pressure data at numerous wellbore positions along the same horizontal well. Then, we interpreted the tested pressure data and compared the test results at different points along each well using the test curve shape and the interpretation parameter values. Through comparisons of the two wells, we found that the well-test curve shape and the interpretation results of tests performed above the kickoff point were completely different from those of the tests at the midsection of the horizontal wellbore under the conditions of a large gas rate and a small water cut. If a horizontal well has a small gas rate and a large water cut, the well can be tested at the kickoff point in the well using the wireline. We recommend that field petroleum engineers adopt the time-tracking test method to judge whether their horizontal wells should be tested at the kickoff point.

Relationship between vertical depth of the kickoff point of a fracking operation and methane concentrations in groundwater resources

There is a problem with hydraulic fracturing and water contamination. Despite Safe Drinking Water Act regulations, risk to water resources remains in areas of water acquisition, chemical mixing, well injection, produced water handling, and wastewater disposal and reuse. This problem has negatively impacted some relying on groundwater resources surrounding hydraulic fracturing operations because of inadequate information (e.g. unmapped faults, abandoned/unfilled wells, unknown mechanisms of risk, etc.). Perhaps a study which investigates the correlation between the vertical depth of the kickoff point (point at which fracking fluids are dispersed underground in vertical wells) and thermogenic methane concentrations in groundwater resources could remedy this situation by filling a gap in the research and identifying a potential risk to groundwater resources. The question: to what extent does the vertical depth of the kickoff point in a fracking operation correlate to thermogenic methane concentrations in groundwater resources?

Kick-Off Point (KOP) and End of Buildup (EOB) Data Analysis in Trajectory Design

Well X is a development well which is directionally drilled. Directional drilling is choosen because the coordinate target of Well X is above the buffer zone. The directional track plan needs accurate survey calculation in order to make the righ track for directional drilling. There are many survey calculation in directional drilling such as tangential, underbalance, average angle, radius of curvature, and mercury method. Minimum curvature method is used in this directional track plan calculation. This method is used because it gives less error than other method. Kick-Off Point (KOP) and End of Buildup (EOB) analysis is done at 200 ft, 400 ft, and 600 ft depth to determine the trajectory design and optimal inclination. The hole problem is also determined in this trajectory track design. Optimal trajectory design determined at 200 ft depth because the inclination below 35º and also already reach the target quite well at 1632.28 ft TVD and 408.16 AHD. The optimal inclination at 200 ft KOP depth because the maximum inclination is 18.87º which is below 35º. Hole problem will occur if the trajectory designed at 600 ft. The problems are stuck pipe and the casing or tubing will not able to bend.

Effect of well trajectory on liquid removal in horizontal gas wells

A systematic experimental study on two-phase air-water was carried out to evaluate effect of well trajectory on liquid removal in horizontal gas wells. Experiments were conducted in a facility with a 2-in. ID and 62.6-ft. long lateral section and a 41-ft. vertical section, which mimics a horizontal well. Four well configurations were considered; namely, toe-down, toe-up, one-undulation with a sump and one-undulation with a hump. Additionally, different flow conditions were used to simulate the well production as the reservoir pressure depletes. The effect of well trajectory on the liquid removal was evaluated measuring the pressure gradient, liquid holdup, film reversal, and flow pattern.Experimental results indicate that under stable conditions, toe-up is the best configuration for the displacement of the produced fluids from the toe to the kick-off point. However, at very low gas flow rates, severe slugging is observed in this configuration. Furthermore, for the toe-down, one-undulation with a sump, and one- undulation with a hump configurations liquid loading is observed in both lateral and vertical sections of the well. Consequently, significant liquid accumulation and an eventual slugging condition are observed in the well. It was observed that the measured critical gas velocity to avoid liquid loading is lower than gas velocity at the minimum pressure gradient, indicating that minimum pressure gradient criterion is not enough to determine whether the well will be under stable or unstable conditions. Finally, toe-down configuration presents the largest liquid accumulation in the lateral section, indicating lower efficiency to remove liquids from the toe to the kick-off point.

Cement-Integrity-Evaluation Solution in Extended-Reach Wells in the South China Sea

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25027, “Solution to Cement-Integrity Evaluation in Long Extended-Reach Wells: New Record in the South China Sea,” by Jun Cai, Yongde Gao, and Mingjie Zhang, CNOOC, and Lei Cui and Hongzhi Guo, SPE, Schlumberger, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25–28 March. The paper has not been peer reviewed. The combination of ultrasonic pulse-echo and flexural-attenuation measurements was adopted in this project in the South China Sea for cement-integrity evaluation. This new method aids in understanding why integrity losses occur in certain sections, by analyzing third-interface information uniquely provided by flexural-wave imaging, and in formulating improvement actions for future cementing jobs. This method achieves a more-explicit cement-integrity-evaluation result with detailed graphical annulus information compared with the limited output from conventional acoustic measurements. Introduction In the Weizhou field in the South China Sea, most of the development wells are drilled as long extended-reach wells with a deviation greater than 70°. The wells are designed to reach more than 70° deviation at a very shallow depth (approximately 900 m) compared with the total depth of the well (approximately 4500 m). In a typical well, surface casing (13.375 in.) runs beyond the kick-off point and reaches maximum deviation of the well at a shallow depth (approximately 900 m). Intermediate casing (9.625. in.) runs from surface to more than 4000 m, with three different fluids/ slurries pumped in the annulus: regular-weight tail cement (1.90 g/cm3), freshwater displacement cement, and lightweight lead cement (1.58 g/ cm3). The completion liner (7 in.) hangs on the intermediate casing, with 1.90-g/cm3 cement pumped in the annulus. A campaign was planned to perform cement-integrity evaluation in five wells (A9, A10, A1, A2, and A3). The basic information about these five wells is listed in Table 1 of the complete paper. The objective for Well A9 was to evaluate the 7-in. completion casing, and the objective for the remaining four wells was to evaluate the 9.625-in. intermediate casing. The well profile and completion pose several challenges: Cementing highly deviated wells has uncertainties associated with cement placement because of the likelihood of poor mud removal, which is generally caused by pipe eccentering. Intermediate casing is cemented with both regular-weight and lightweight cements. A more advanced method to evaluate the material in the annulus independently of its density is required for this project. The geometry of casing in the borehole is important information in this type of well because it is the main factor affecting the cement placement in the annulus. The logging tool string is not able to be conveyed by wireline only because of the high deviation along the wellbore. An alternative conveyance needs to be performed in an efficient manner.to save rig cost. For a discussion of the conveyance-selection process that resulted in the selection of a wireline tractor, please see the complete paper.

Eagle Ford Shale Well Control: Drilling and Tripping

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163984, ’Eagle Ford Shale Well Control: Drilling and Tripping in Unconventional Oil and Gas Plays,’ by K. Ridley, SPE, M. Jurgens, SPE, R.J. Billa, SPE, and J.F. Mota, SPE, Shell, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28-30 January. The paper has not been peer reviewed. In late 2010, Shell began an Eagle Ford appraisal program in the Piloncillo Ranch lease in south Texas. These wells are 8,500- to 9,500-ft-true-vertical-depth (TVD) horizontals, with an average total depth of 14,500-ft measured depth (MD). Initially, underbalanced-drilling techniques were used to drill the formation. As more wells were drilled, completion fracturing of offset wells began to cause well-control problems as induced fractures were encountered in horizontal sections during drilling. The authors describe the development of well-control techniques that allowed successful drilling operations. Well Design The original pore-pressure concept drove the field to a basic two-string casing design. The wells have 9?-in. surface casing and 5½-in. production casing. The surface-casing point was designed to be set between 3,000- and 3,500-ft TVD in the Midway shale below the base of the freshwater aquifer, which varies between 2,000- and 2,800-ft TVD. The fracture strength at this point was found to be 17 lbm/gal equivalent mud weight (EMW), which was considered to be sufficient for kick tolerance through the openhole interval to total depth (TD) in the Eagle Ford. The next hole section is then drilled out of the surface shoe to the kickoff point in the Austin chalk and landed in the upper Eagle Ford, where a 5,000-ft lateral section is drilled. The bottomhole assemblies (BHAs) were optimized until one run was possible from drilling out the surface shoe to TD of the well. The fracture strength of the surface shoe, along with the assumed pore pressure of 12.5 lbm/gal EMW in the Eagle Ford, allowed for a two-string design. This initial appraisal phase consisted of single-well pads with 5,000-ft laterals along a preferred azimuth. With further field development, the plan was set with multiwell pads in order to minimize the footprint and reduce undeveloped space in the reservoir (Fig. 1). Drilling—Phase 1: Initial Wells The first wells were drilled with a mud weight (MW) of 11.0 lbm/gal and exhibited few well-control challenges. No flow was observed while making connections or when performing flow checks at TD, and minimal background gas while drilling and at bottoms-up upon reaching TD was common. There was no flare during drilling, but the flare at bottoms-up at TD averaged between 10 and 20 ft. Previous experience in the Eagle Ford and other tight gas plays showed this level of gas to be manageable with a conventional rotating control device and a mud/gas separator. Some losses were encountered during the initial 5½-in.- production-casing cement jobs with a two-slurry design of top of cement at surface and a 12.7-lbm/gal lead and 16.4-lbm/gal tail. This was attributed to formation weakness in the Olmos sand, which occurred from 5,300- to 6,700-ft TVD. Equivalent-circulating- density simulations established this formation as a potential weak point, with an estimated fracture strength between 13- and 14-lbm/gal EMW across the field.