bluuebunny/crossref_metadata_2025 huggingface dataset:
Sucker Rod Anti-Buckling System to Enable Cost-Effective Oil Production
Authors: Clemens Langbauer , Rudolf Fruhwirth , Manuel Hartl , Herbert Hofstätter
Published: October 2018

In days where the oil price is low, cost optimization is of vital importance. Especially in mature oil fields, the reduction of lifting costs by increasing the mean time between failure and the overall efficiency helps to stay economical and increase the final recovery factor. Today a significant portion of artificially lifted wells use sucker rod pumping systems. Although its efficiency is in the upper range, compared to other artificial lift systems, there is room for improvement and system optimization.

This paper presents the benefits of the field-tested Sucker Rod Anti-Buckling System (SRABS), which can entirely prevent compressive loads from the sucker rod string by a redesign of the standing valve, the advantageous use of the dynamic liquid level, and the on a case-by-case basis application of a tension mass. This results in complete buckling prevention and a reduction of the overall stress in the sucker rod string.

The resulting reduction in the number of well interventions in combination with the higher overall pumping efficiency prolongs economic production in mature oil fields, even in times of low oil prices. The analysis of SRABS, using simulations, showed a significant increase in the overall efficiency. The SRABS performance and wear tests under large-scale conditions are performed at the Montanuniversitaet Leoben's Pump Testing Facility and in the field. The self-developed Pump Testing Facility can simulate the conditions of a 500 m deep well, including the effects of dynamic liquid pressure and temperature. Testing of SRABS has identified major benefits in comparison to standard sucker rod pumps.

The results of intensive testing are used to optimize the geometry of the pump body itself and to improve the wear resistance by selecting optimal materials for the individual pump components. SRABS itself can be applied within every sucker rod pumping system; the installation is as convenient as for a standard pump, and manufacturing costs are comparable with those of a standard pump. This paper shows the high performance of the SRABS pumping system in comparison to a standard sucker rod pump.
Depleted Drilling System: Use of Aerated Mud in Surat CSG Wells
Authors: Bhavnani Pankaj , Richards Dylan
Published: October 2018

The operator's strategy is to maximise economic upstream gas production by drilling technically-mature sustaining wells in depleted areas of Surat basin in Queensland, Australia. To date the operator has drilled more than 2800 Coal seam gas wells with minimal well control issues.

Historically wells drilled in Surat basin were normally pressured vertical wells with depths ranging from 600-1000m TVD. The wells are drilled with water + KCL (weighting agent) with mud weight in range of 8-6-9 ppg. However, few wells drilled in late 2016/17 in Central Surat area showed signs of significant depletion in terms of drilling fluid losses and multiple well control events which suggested that prolonged production from these coal seams have reduced the reservoir pressure & correspondingly fracture gradient. Those wells were controlled with conventional well control methods. But this had an impact on the well duration and the wells were drilled at considerable cost. This prompted the Well Engineering team to look for alternative mud systems which can reduce the losses to coals and any reservoir productivity impact.

This paper represents the well planning and design process undertaken to drill these depleted wells with a Near balanced fluid system – Aerated mud (a combination of water and air). The author also has included operational results from four trial coal seam gas wells drilled with Aerated mud. The objective of the trial was to understand the impact of drilling the depleted coal seams with lighter fluid and any time/cost impact.
Porosity Determination via Contrast Enhanced Micro CT Scanning and Digital Core Analysis: A Case Study of X Field
Authors: Sazali Wan Muhammad , Md Shah Sahriza Salwani , Kashim M Zuhaili , Kantaatmadja Budi Priyatna , Knuefing Lydia , Young Benjamin , Goodwin Carley
Published: October 2018

There are a number of additional challenges in the development of high CO2 content gas fields. To meet the requirements of the Kyoto Protocol and Paris Agreement, an efficient means to deal with the produced CO2 such as re-injection into the reservoir for sequestration is required. With the intention of developing such high CO2 gas fields, PETRONAS has identified a trial candidate (X field) offshore Sarawak Malaysia, which is a carbonate gas field with 70% CO2 content and good potential to re-inject the produced CO2 into the field's aquifer zone. To study the feasibility of CO2 reinjection, PETRONAS R&D team are studying the effects of re-injected CO2 on the mineralogical and petrophysical properties of the reservoir and decided to incorporate Digital Core Analysis (DCA) into the case study. Although porosity determination and other petrophysical property characterisation using micro-CT images has been widely used for a number of years, there is still discussion about its accuracy and reliability. Based on previous internal studies, porosity determination via digital core analysis can be limited by the quality and resolution of micro-CT images collected and thus the capability of the image analysis software. This case study investigates accuracy and reliability of the use of contrast enhanced imaging practices and the use of the helical micro CT for porosity determination via Digital Core Analysis (DCA). PETRONAS adopted and optimized a contrast enhanced imaging methodology for use on 1-inch core plugs during scanning via a helical micro-CT and applied this as a case study to X field with the help of a technology partner to evaluated digital core analysis. In the same year, a commercially available image analysis software was launched, with such a DCA workflow in mind. Using this optimized methodology and the newly launched imaging software, the porosity values from DCA of the 1-inch core plugs show good correlation to the values from Routine Core Analysis (RCA) done on the same samples, with less than 1.5 porosity unit difference. In this case study, PETRONAS managed to compare the porosity obtained from DCA directly with porosity measured by RCA. This methodology will be used for porosity determination for wells or other regions of interest where limited samples or different sample sizes are not suitable for RCA.
Axial Oscillation Tool Combined with Optimized Bent Motor BHA's Successfully Drills Record 3D Horizontal Granitic Basement Section in Vietnam
Authors: Bui Son , Ngo Hai , Nguyen Nam , Blackwell Geoff , Trethewey Jake
Published: October 2018

One of the most challenging drilling applications in Vietnam is granitic basement drilling, where the formation is very hard (35-40Kpsi UCS), not drillable with polycrystalline diamond compact (PDC) cutters, and high vibration levels are experienced. There are many common issues and risks, but despite the challenges, Thang Long Joint Operating Company planned to drill a 3217m 3D horizontal granite section hitting all three targets: building inclination from 20 degrees to 85.6 degrees, holding the lateral, and turning from 62°to 14.3°azimuth, total depth (TD) at 6280m measured depth (MD).

A scientific approach using torque and drag modelling, relevant offset data, and an axial oscillation tool (AOT) to prove drilling to TD is achievable within the acceptable cost and time frame was proposed. A torque and drag model was built from the longest extended reach drilling (ERD) basement section drilled in 2014 (Well X, a 2D well, TD at 7300m MD, 3035m basement section) to understand drilling conditions and limitations. The results were applied in the torque and drag model of the subject well (Well Y). Bent motor bottom hole assemblies (BHAs) were then designed and optimized to minimize string buckling. The modelling was run again, and axial oscillation tools were placed in appropriate zones of each BHA.

The first eight BHAs from the beginning of the granite section at 3063m MD to 5071m MD (completed the horizontal turn at 4313m MD, then held tangent) performed well and stayed close to the planned trajectory. The torque and drag model was continuously updated after each run to predict and prepare the BHA for the next run. From 5071m MD to TD at 6280m MD, optimized bent motor BHAs in combination with two axial oscillation tools were utilized to achieve the directional drilling plan and hit all targets. Two rotary steerable system (RSS) BHAs were used to test an alternative steering solution in granite basement. Both BHAs were unsuccessful in holding the well angle, and repeatedly failed to correct the well path.

The use of axial oscillation technology provides a solution to drilling the granitic basement in Vietnam, which has proven to save operators time and reduce costs, as well as facilitate a more complex and longer basement section to connect multiple pay zones to be planned in the future.
Fracturing with Pure Liquid CO2: A Case Study
Authors: Meng Siwei , Yang Qinghai , Chen Shi , Duan Yongwei
Published: October 2018

After three years of technological breakthrough and field practices, a complete set of patented waterless fracturing operation technology and supporting equipment with independent intellectual property rights have been invented. Obvious oil production increase effect has been observed in multiple field tests on tight sandstone oil reservoir. In this paper, the latest development of Chinese liquid CO2 fracturing technique is introduced through a case study of typical well.

The target depth of operating well is 1730.8m-1757m, with a daily fluid production of 1.6t and oil production of 0.5t, indicating that the displacement relationship has not been effectively established. The fracturing treatment was carried out using the independently developed equipment system, which has treatment capability of available pump rates up to 12 m3/min, sand transportation of 27 m3 and CO2 injection of 1000 m3. During this operation, 860m3 liquid CO2 was injected at a displacement of 5-6m3/min. and 23m3 proppant was preloaded and totally pumped into reservoirs with maximum instantaneous proppant concentration of 12%.

After the fracturing, the daily fluid production increased from 1.9t to 3.9t, the daily oil production increased from 0.7t to 2.3t and the water cut decreased from 63.2% to 41.0%, achieving a significant increase in production. In addition, the oil pressure of one adjacent well increased from 0.5Mpa to 12.4Mpa and the daily oil production of four adjacent wells increased by 0.7-1.1t through the energy enhancement and miscibility of CO2.

The field test shows that liquid CO2 fracturing technology has a significant effects of energy storage and stimulation, adjusts the injection-production relationship effectively, and greatly enhances the single well production. It is expected to become the key technology of the development of tight sandstone oil resources.
Ground Breaking Technology in Artificial Lift; 1st Installation of Full Digital Intelligent Artificial Lift DIAL System at DL field, Brownfield Offshore Malaysia
Authors: Ismail Syahezat , Sy Rahim Sy Puteh , Yahia Zaidil , Elshourbagi Saied Mustafa , Ishak M Faizatulizuddin , Roslan M Rizwan , Che Hamat W Afiq , Ben Amara Abdel , Faux Stephen , Makin Graham
Published: October 2018

Objectives/Scope

Moving to digitalization era in the current low oil price environment, paradigm shift is really crucial in managing brownfield development and production. The challenge is to select the best technology to harvest the optimum production from the field but at the same time reduce potential capital and operating expenditure.

Methods, Procedures, Process

The paper highlights the technology evaluation of Digital Intelligent Artificial Lift (DIAL) system. This includes it's working principles, candidates screening, risk mitigation plan as well as technology success criteria developed specifically for the technology.

DIAL system is an in-well gas lift system that can overcome the well design and operational limitations of existing side pocket mandrels and valves. DIAL enables a better gas lift well design as well as able to interconnect downhole and surface monitoring & control in real-time. It provides opportunity for automation, better subsurface and surface integration as well as minimizing well intervention requirement.

Based on the promising technology evaluation, one pilot well was identified by the team at DL field. The well was part of DL drilling campaign executed in Q2 2018. Details of the well design & scope, as well as gas lift design for the well will be shared. Commercial comparison was demonstrated between conventional side pocket mandrel system and the DIAL system.

Results, Observations, Conclusions

The case study at DL field will be discussed in details, starts from their wells’ design, technology deployment strategy, installation, production test result as well as lessons learnt during installation and operationalization of the system.

Moving forward from the pilot application, root cause failure analysis was done, lessons learnt were identified, design improvements were proposed and continuous monitoring of the system will be done, according to the success criteria outlined. Potential replication candidates have also been identified by the team with at least 10 promising potential candidates to be installed within the next 2 years.

Novel/Additive Information

The technology deployment was the result of collaborative works between PETRONAS, Silverwell Energy and Neural Oilfield Service.
Research of Non-Stop Intermittent Pumping Production for Beam Pumping Units
Authors: Gong Hongliang , Sun Yanan , Zhang Shujin , Qi Xing , Shi Guochen , Sun Chunlong , Wang Guoqing , Zhang Deshi , Wei Feng , Yu Hou , Qing Changrui , Zheng Guoxing , Zhao Yulong , Gao Yang
Published: October 2018

A new technology of the non-stop intermittent pumping production for beam pumping units has been widely used in PetroChina Daqing oil field. This technology solves the problems that existed in conventional intermittent pumping production, such as a large fluctuation in fluid level, a long idle time, high labor intensity, frozen wellhead in winter, and difficulty in management, etc.

This technology adopts a new strategy. It transforms a long-period intermittent pumping into several short-period intermittent pumping, and changes the crank from shutdown into low-energy swinging motion, at the same time, the plunger piston at downhole is kept stationary while the crank does do non-stop swing operation. Based on the maximum elastic deformation of sucker rods, the optimal swing range and rotary speed of crank are designed by kinematics and load analysis. Meanwhile, the inverter increases the swinging amplitude of crank to build up the gravitational potential energy. With conversion effects from gravitational potential energy to kinetic energy, as well as active control of swing power, a non-impact low energy swinging scheme is formed. The flexible switch between complete-cycle pumping operation and swing operation is successfully realized. According to the situation of a single well, the corresponding working system is formulated.

A total of 124 wells had been used this new technology in petroChina Daqing oil field, the filed application shows that, the non-stop intermittent pumping production stabilizes the fluid level within a reasonable range and guarantees a better pump fillage. Compared with the conventional intermittent pumping prodution, the pump efficiency improved 6.54%, the average energy-saving rate ran up to 34.59%. It is significantly improved the pump efficiency and system efficiency, and achieved the purpose of energy saving. The technology of the non-stop intermittent pumping production for beam pumping units is appropriate for the low-yield well and insufficient liquid well. It will be of great significance for the high-efficiency development of low-yield well.
Technology of Fire Flooding Process Control: Application to Fire Flooding in a Deep and Thick Heavy Oil Reservoir in China
Authors: Feng Tian , Wu Yi , Hu Changhao , Gong Yuning , Song Yang
Published: October 2018

Fire flooding process has been applied to the thick and deep heavy oil reservoirs G3618 and G3 in Liaohe oil field in China. Currently, there are two main operating issues: the serious combustion front gravity override, and the low areal sweep efficiency. Thus, research of process control is conducted for the entire project area, each layer, and also individual well patterns, with the objective of achieving better vertical and areal conformance.

G3 and G3618 have average thickness of 68.6m and 103.8m, with similar depth of 1600m. Three major process control methods are used: using vertical-horizontal well configuration, reconfiguring to line drive plus vertical-horizontal hybrid configuration, and air injecting at top positions. We establish geological model with focus on interlayer vertical communications. Through reservoir simulation and field data analysis, we test potential benefits of using horizontal producers. We further compare the different performances of line drive and pattern flood in G3618 and G3. Finally, with G3618 having 20 degree dip angle, we test the effect of air injection at higher elevations through simulations and laboratory experiments.

First, we have found 2m as the critical thickness for shale interlayer barriers to prevent vertical communications and to minimize gravity override. The combination of vertical and horizontal wells shows great improvements in conformance, since the horizontal producer at bottom of the reservoir could more effectively drain the reservoir. Second, we find line drive is more effective than pattern flood with recovery improvement of around 10%, proven by reservoir simulations and field production analysis. Third, if we inject from top, we benefit from high recovery of gravity drainage, with much oil accumulated at reservoir bottom. We recommend conducting top injection when reservoir thickness is above the critical value of 20m. Finally, we have establish line drive fire flooding configuration in G3 reservoir with air injectors located at top positions of the reservoir, which causes oil production rate to increase by about 80% since initiating these adjustments. For G3618 reservoir, we have also reconfigured the well patterns to line drive with air injectors at elevated locations, with daily production rate increased by 30%.

Through field experience, we have found that controlling combustion front override and improving areal sweep efficiency are great technical challenges for fire flooding process. We demonstrate that measures of implementing line drive, injecting at the top while producing at deeper locations, and configuration of vertical injectors and horizontal producers have already made significant improvements in fire flooding production performance in Liaohe oil field in China.
Deep Learning Convolutional Neural Networks to Predict Porous Media Properties
Authors: Alqahtani Naif , Armstrong Ryan T. , Mostaghimi Peyman
Published: October 2018

Digital rocks obtained from high-resolution micro-computed tomography (micro-CT) imaging has quickly emerged as a powerful tool for studying pore-scale transport phenomena in petroleum engineering. In such frameworks, digital rock analysis usually carries the problematic aspect of segmenting greyscale images into different phases for quantifying many physical properties. Fine pore structures, such as small rock fissures, are usually lost during segmentation. In addition, user bias in this process can lead to significantly different results. An alternative approach based on deep learning is proposed. Convolutional Neural Networks (CNN) are utilized to rapidly predict several porous media properties from 2D greyscale micro-computed tomography images in a supervised learning frame. A dataset of greyscale micro-CT images of three different sandstones species is prepared for this study. The image dataset is segmented, and pore networks are extracted to compute porosity, coordination number, and average pore size for training and validating our model predictions. The greyscale images (input) and the computed properties (output) are uploaded to a deep neural network for training and validation in an end-to-end regression scheme. Overall, our model estimates porosity, coordination number, and average pore size with an average error of 0.05, 0.17, and 1.8μm, respectively. Training wall-time and prediction error analysis are also discussed. This is a first step to use artificial intelligence and machine learning methods for the robust prediction of porous media properties from unprocessed image-driven data.
Dynamic Modelling of Walloon Coal Measures: An Unsavoury Cocktail of Reservoir Variability, Mismatched Resolutions, and Unreasonable Expectations
Authors: Cardwell Joshua
Published: October 2018

A full-field dynamic simulation model has traditionally been seen as the benchmark for assimilating all available static and dynamic data to develop robust production forecasts. Santos’ experience modelling the Walloon Coal Measures in its Surat Basin acreage has shown that the performance of individual wells producing from this CSG reservoir is governed by reservoir variability at a fine-scale. This presents a fundamental challenge in developing full-field dynamic models that can accurately describe and predict production performance down to the scale of individual coal seams.

Current Queensland CSG projects have focussed on the most prospective acreage, however as subsequent developments move to more marginal areas a greater understanding of the subsurface will be required for optimum development. The target formations will increase in geological complexity, such as Santos’ Surat Basin acreage on the edge of the CSG fairway. Here wells produce from a greater number of distinct coal reservoir units, and how these reservoir units are structured and relate to each other governs reservoir connectivity and defines long-term production performance. Each reservoir unit is comprised of multiple coal plies, all with their own unique maceral distribution and cleating characteristics. These fine-scale properties define the reservoir's dynamic behaviour, and can be impossible to upscale such that these characteristics are preserved at a coarse scale. Consequently, accurately modelling individual well performance will require a fine-scale model to capture and characterise this variability.

In development areas where the quantity and quality of reservoir data gathered from exploration and appraisal is sparsely populated, these fine-scale models will need to be populated geostatistically. Without model-scale appropriate control data from production and pressure measurement in the development wells to provide constraints however, a probabilistic model will not accurately define fine-scale behaviour of specific reservoir units. These data requirements can help shape the appraisal scope for new areas and define an appropriate level of surveillance for producing assets.

Traditional full-field dynamic modelling has fundamental limitations for interrogating complex unconventional CSG reservoirs at a fine scale. Because of this, alternative workflows are required to answer the subsurface questions necessary to develop CSG assets such as the Surat Basin effectively. This paper details a selection of workflows explored to address this pragmatically, as well as their limitations and associated data requirements. This will also assist in identifying data gaps needed for optimum reservoir management and to aid in the development of these challenging CSG reservoirs.
Prediction of In-Situ Stresses and Pore Pressure in a Shale Gas Reservoir Subject to Finite Fault Slip
Authors: Lin Botao , Jin Yan , Chen Yun
Published: October 2018

The shale reservoirs in Sichuan Basin, west China, are located in a geological region plagued by frequent seismic activities. Fault slips can induce significant time-dependent stress and pore pressure changes in those reservoirs. In order to properly drill a stable wellbore or perform hydraulic fracturing, it is desired to evaluate the state of in-situ stresses and pore pressure after slip of faults at relatively close distances to the wellbore. The surrounding solid matrix was assumed to be linear elastic and fluid infiltrated. First, the in-situ stresses of a horizontal rectangular fault subject to shear dislocations along its edges were analyzed based on poroelasticity. Secondly, the solutions were projected to a fault having specific strike and dip angles. The direction and magnitude of fault slip were recorded from the three-dimensional seismic profile. The pore pressure was calculated based on the predicted stresses using Skempton's coefficients. Finally, the complete stress and pressure fields were derived from superposition of the solutions with the static analysis results from using the finite element (FE) method on the continuum reservoir. It was found that the mean normal stress σ and octahedral shear stress τ induced by a finite fault slip exhibit antisymmetric patterns about each fault edge if the dip angle φ is zero, and decrease rapidly with distance to the fault plane. The contours gradually distort with an increase of φ while being much less sensitive to the strike angle θ. In addition, the magnitude and extent of the induced stress or pressure enhance with slip magnitudes. Implementing the poroelastic approach to a shale reservoir in Weiyuan region of Sichuan province in southwest China disclosed that the predicted maximum and minimum stress curves match the measured data satisfactorily. Meanwhile, the induced pore pressure is significantly dependent on the Skempton's B coefficients of the shale matrix. In summary, this study provides a poroelastic means to quantitatively predict the 3D in-situ stress and pore pressure fields in a shale reservoir with finite faults, which have reservoir stratigraphy as well as fault dimension and slip obtained from interpretation of the seismic profile.
Comparing Carbon Intensity of Unconventional and Asia Pacific Oil Production
Authors: Meehan D. Nathan , El-Houjeiri Hassan , Rutherford Jeffrey S.
Published: October 2018

Carbon intensity (CI) of oil and gas production varies widely across global oil plays. Life cycle extraction from certain unconventional plays (e.g., tar sands) have the highest CIs but even many North American shale plays have high CI. Flaring and venting of associated or non-associated natural gas dramatically increases CI. This paper applies peer-reviewed processes across broad averages of shale activity in North America and compares them with CI in countries in the Asia Pacific region. Ways to lower the carbon intensity in both areas are discussed.

We perform well-to-refinery calculations of CI for major unconventional oil plays in North America and conventional plays in Asia Pacific. This approach accounts for emissions from exploration, drilling, production, processing, and transportation. The analysis tool is an open-source engineering-based model called Oil Production Greenhouse Gas Emissions Estimator (OPGEE). OPGEE makes estimates of emissions accounting using up to 50 parameters for each modeled field. This model was developed at Stanford University. Data sources include government sources, technical papers, satellite observations, and commercial databases.

Applied globally, OPGEE estimates show highest values in areas with extensive flaring of natural gas and very heavy crude oils - heavy oils require large energy inputs (e.g., steam flooding) and/or the use of light hydrocarbon diluents for transportation offset. A few other major areas included for reference. Examples illustrate how OPGEE can be used to evaluate the CI of public policy actions. A sensitivity analysis to flaring volumes illustrates these impacts, and further sensitivity analyses to pad drilling and improving well performance show CI impacts associated with hydraulic fracturing.

Unconventional production, especially from light tight oil is the most significant new source of fossil fuels in the last decade. Under a wide variety of carbon constraints, oil usage will continue for many decades and increase in the near term. Operators, governments, and regulators need to be able to avoid "locking in" development of suboptimal resources and instead provide incentives for shale operators to manage resources sustainably. This approach provides quantitative measures of such actions. Oil producers must prepare by eliminating development of marginal projects, elimination of flaring and venting, optimizing hydraulic fracture treatments, using improved recovery methods (e.g., enhanced oil recovery using anthropogenic CO2), reducing energy use, and eliminating unnecessary gas waste.
Alleviating the Solids Issue in Surat Basin CSG Wells
Authors: Kalinin Daniel , Choo Daryl , Watling Ashley , Liu Hai , Kong Teng Ling , Soo Hui Gog
Published: October 2018

A system for reducing solids production in Surat basin coal seam gas (CSG) wells was developed in the laboratory and tested in the laboratory and field trials.

Several thousand CSG wells were completed in Surat basin in eastern Australia using what was considered an economic method at a time - an open hole with a predrilled liner.

Although the majority of the wells are meeting production expectations, a many wells are producing a substantial amount of solids originating from an interburden rock representing approximately 90% of completed interval length and comprising mudstones, sandstones, and siltstones rich in illite/smectite and other water-sensitive clays. Relatively fresh water, with total dissolved solids (TDS) of approximately 4000 to 7000 mg/l, produced from multiple thin coal seams during dewatering and production phases is causing the interburden rock to swell or disintegrate. Prolific wells with high water rates or high gas velocity are capable of carrying solids to the surface where the solids are deposited in separators, flowlines, and water-treatment settling ponds. Higher solids concentration on lower-rate wells are causing issues with positive cavity pumps (PCP), the artificial lift method of choice in CSG wells. Pump intake plugging with solids, excessive torque and rotation seizure, and wear of tubing/rod strings are frequent causes of workovers and shorter-than-expected pump run-life. Some wells are able to flow freely; however, an extra monitoring program is required to ensure wellheads are not suffering from solids-induced erosion.

Recompletion of the wells is not considered practical at this stage because pre-perforated joints form an integral part of the 5 ½-in. or 7-in. casing string, which is cemented above the Walloons subgroup coal seams. An external casing packer (ECP) is often used. Some coal seams were underreamed, thus further complicating recompletion. Plugging existing wells and drilling a pair of wells using same surface location and infrastructure have been considered.

A chemical wellbore stabilization solution been developed to alleviate/stop solids production from the interburden rock. The treatment comprises two fluids separated by a spacer that contains clay stabilizer that is typically 3 to 7% KCl, the same as drilling mud base. Proprietary surfactant reduces the possibility of coal damage. Regained permeability testing performed using crushed and sieved coal pack plugs indicated a low level of damage. The wellbore stabilization system could be energized/foamed to reduce hydrostatic pressure and increase compressibility, hence increasing the chance of contacting rock surface in an enlarged wellbore.
The Application of Flexible Coiled Composite Pipe in Onshore Oilfields in China
Authors: Ming Eryang , Li Tao , Li Yiliang , Pei Xiaohan , Hao Zhongxian , Guo Tong
Published: October 2018

In recent years, the flexible coiled composite pipe (FCCP) has developed rapidly in China. Because of its merit about chemical inertness, it has been introduced to onshore oilfields to endurance some severe situations, such as serving as tubing in corrosive and waxy oil wells, as tubing in scaling water injection wells or as surface gathering pipelines, especially suitable for mountainous areas. This paper will introduce the development status of FCCP in different applications.

According to our research and development, for FCCP structure manufacture, there are two main technical routes in China, non-adhesive pipe and adhesive pipe. These two kinds of pipe meet the merits of FCCP, however, there are some differences in technical parameters. Obviously, non-adhesive pipe has smaller bending radius, but the integrity of adhesive pipe is better which is good for fitting installation. In this technical stage, the FCCP has been applied in surface gathering system, general water injection system and rodless artificial lift system.

For surface gathering system, this is the most mature application of this technology. It has been laid over 30,000 kilometers. Compared with steel pipe, the equipment of FCCP is simple and high laying efficiency. For general water injection system, the FCCP replaces steel pipe by high working efficiency and long endurance. It has been applied more than 80 wells. For rodless artificial lift system, there are almost 60 wells applied FCCP. It is the severest running condition for FCCP with high temperature, high wellbore pressure and high varies suspension force. This application reveals the advancement of FCCP by twining cables inside the pipe body and adding functions of real-time monitoring and heating. Two typical applications are serving as tubing in cold heavy oil production and acid gas corrosion oil well. The application of FCCP has made great progress. But there are several key issues that need to be resolved in the future research. First, there is lack of post evaluation of performance. Second, the limit of material working temperature shrinks the application scope. Third, the external pressure resistance is limited.

This paper shows the applications of flexible coiled composite pipe in onshore oilfields of China in the past 5 years, including a summary of technical experience, and proposing the goal of further research.
Case Study for Performance Benefits of Cased-Hole Logging in Coal Bed Methane CBM
Authors: Mastin Stephen , Pfahl Matthew , Jukes Rachael
Published: October 2018

This paper presents a case study review of the performance benefits of a 66 well Coal Bed Methane (CBM) development program whereby cased-hole (CH) logging was introduced as a substitute for open-hole (OH) logging. This paper demonstrates how the reduction in OH logging requirements improved time and cost performance and reduced risk exposure while maintaining suitable data quality.

The approach was based on utilizing existing offset well data and three-dimensional (3D) seismic data to substitute OH density logging for CH density logging. Therefore reducing critical path time on the drilling rig and risk exposure with wireline logging tools in an OH environment. A qualitative and quantitative approach to review rig performance and cost benefits was subsequently undertaken.

The density log was of key importance as it is used to define net coal thickness in CBM reservoirs. Current CH density logging typically results in the reduction of log resolution and accuracy which limits the ability to resolve thinner coal seams. The loss of coal definition has the potential to result in the under-estimation of net coal for reserves purposes, impact static modelling and possibly negatively impact fracture stimulation decisions.

The 66 well development program provided a suitable data set to quantify the performance benefits of a combined CH and OH evaluation program. The transition to CH density logs removes online evaluation activities during the drilling operation. This provides a direct time and associated spread cost saving. In addition, unsuccessful OH logs were replaced with CH density logs when hole conditions presented higher likelihood of unproductive and high risk operations (tight hole/fishing). The campaigning of CH logging operations further optimized both wireline and operating company resources and time. The CH density logs provided suitable data to adequately identify coal targets in order to stimulate and complete the wellbore. The reduction in log resolution and coal identification was overcome by developing 'optimized' density cut-offs based on a calibration study with OH density wireline data.

This case study supports the use of CH density logs in lieu of OH density logs where feasible for CBM reservoirs. It demonstrates the operational optimizations and cost savings by conducting wireline logging operations offline while also reducing risk exposure to down hole issues.
Using Machine Learning to Predict Lost Circulation in the Rumaila Field, Iraq
Authors: Al-Hameedi Abo Taleb , Alkinani Husam H. , Dunn-Norman Shari , Flori Ralph E. , Hilgedick Steven A. , Amer Ahmed S. , Alsaba Mortadha T.
Published: October 2018

Lost circulation costs are a significant expense in drilling oil and gas wells. Drilling anywhere in the Rumaila field, one the world's largest oilfields, requires penetrating the Dammam formation, which is notorious for lost circulation issues and thus a great source of information on lost circulation events.

This paper presents a new, more precise model to predict lost circulation volumes, ECD and ROP in the Dammam formation. A larger data set, more systematic statistical approach, and a machine learning algorithm have produced statistical models that give a better prediction of the lost circulation volumes, ECD, and ROP than the previous models for events. This paper presents the new model, validates the key elements impacting lost circulation in the Dammam formation, and compares the predicted outcomes to those from the older model.

The work previously in the literature provided a platform for predicting the severity of lost circulation incidents in the Dammam formation. Using the new models, the predictions closely track actual field incidents of lost circulation. When new lost circulation events were compared with predictions from the old and new models, the new model presented a much tighter prediction of events.

Three equations for optimizing operations were developed from these models focusing on the elements that have the highest degree of impact. The total flow area of the nozzles was determined to be a significant factor in the ROP model indicating that nozzle size should be chosen carefully to achieve optimal ROP.

Good modeling of projected lost circulation events can assist in evaluating the effectiveness of new treatments for lost circulation. The Dammam formation is a significant source of lost circulation in a major oilfield and warrants evaluation of the effectiveness of lost circulation treatments. These techniques can be applied to other fields and formations to better understand the economic impact of lost circulation and evaluate the effectiveness of various lost circulation mitigation efforts.
Assesing Well Placement in Multi Faulted Reservoir
Authors: Vevakanandan Valsan , Ting Angelina , Zhang Tingting , Maula Fahdi , Ahmad Aqil , Santoso Gagok , Alang Khairul
Published: October 2018

K field is a faulted anticline structure lying in a turbidite environmental setting, which consists of two main sand bodies of 50-100ft gross thickness. Two main challenges during development stages were, 1). The narrow thickness of the fault block requiring accurate landing, well placement and characterization. 2). The low vertical permeability inside the sand which requires the straddling and precision of horizontal placement relative to reservoir boundary. Geosteering was proposed to mitigate those challenges, which is then translated into a directional drilling plan. Hybrid LWD combination of Seismic, Reservoir Mapping, RT-Image and Formation Pressure While Drilling technology were used overcome those objectives and challenges. Seismic was used to update target uncertainty in both depth and lateral coordinates, hence accurate landing inside the target fault block was the main driver. Reservoir Mapping Technology and borehole images were used to update the presence of fault and plan for an accurate placement of the horizontal section. Pressure While Drilling was used to update the reservoir pressure and fault/ connectivity between fault/compartments. Post job subsurface modeling was updated using those measurement for accurate interpretation, which was used for future field development plan.

The drilling workflow was extensively discussed among the stakeholders to make sure it was fit for purpose and could achieve the objectives. Horizontal well landing procedures using Seismic While Drilling technology helped the well penetrate into fault block A at 100m before fault edge. Reservoir Mapping While Drilling technology enabled successful Geosteering inside the desired target zone. Another important application regarding the Reservoir Mapping Technology is the capability of resolving the internal sedimentary bedding feature (higher dip feature) and the delineating of multiple faults including sub seismic fault block B, which helped the team define well TD at the desired fault block position. An integrated interpretation between Reservoir Mapping While Drilling, High Resolution Images and Formation Pressure While Drilling to detect pressure continuity between one block to the other proved to be very helpful for production management and completion optimization. At the end, two horizontal wells were successfully drilled in the desired fault block. Everything worked, ie the technology, the people and the process, resulting in an accurate and well controlled execution of a complex and high-profile project.

The novel approach was successfully demonstrated to ensure well objectives are achieved in an integrated manner. The flawless execution allowed the team to avpid drilling any side tracks which would have been costly.
An Open Approach to Drilling Systems Automation
Authors: Brackel Hans-Uwe , Macpherson John , Mieting Ralf , Wassermann Ingolf
Published: October 2018

The promise of drilling systems automation is to increase well construction efficiency, delivering quality wells in a safe, reliable and predictable manner. This promise is achieved in part by creating a digital infrastructure that extends vertically from the drill bit to the remote enterprise, and horizontally from exploration to production. Critical to the success of automation is the unimpeded flow of quality data through this infrastructure. This paper focuses on studying only drilling systems automation, but the lessons learned can be applied to other disciplines such as completions and production.

Due to the disconnected nature of the well construction business with multiple disciplines and companies involved, data silos and restrictions are numerous. This paper describes the development of a wellsite-based automation system consisting of an open data aggregator, with networked surface and downhole sensors and real-time applications for process monitoring, advice and control. The data aggregator is designed to allow all relevant parties to access and share data in a high-velocity deterministic environment. This access and sharing permits easy implementation of comprehensive drilling system automation, be it monitoring, advising or control, in a controlled, productive and safe manner. The paper also describes the implementation of automation applications using data from the aggregator, covering real-time drilling optimization and hydraulics.

Operation of the data aggregator at the wellsite with connection to rig systems and remote operating centers is described. The data aggregator uses protocols that are international standards, and it is designed to be open and not proprietary. From an implementation standpoint, this allows easy interface of the aggregator to measurement and control systems, and access to copious third-party communication products, reducing development time and increasing reliability. Observations are that many rig instrumentation and control systems use either customized or proprietary protocols; common data information standards are lacking in the oilfield. In addition, data ownership and governance must be addressed at an industry level, as well as secure bi-directional flow of data between wellsite and town. While these topics are, to some extent, being addressed in industry road-mapping and guidance groups, progress is slow and this hinders the adoption of technology.

The paper describes the development and implementation of an open data aggregator for the wellsite. The aggregator allows third-party real-time applications to use and share data, and to collaborate on industry standards. It further describes the development of automation applications riding on the data aggregator, and their use in drilling systems automation. This case study illustrates and examines issues that must be addressed at the company and industry level to move universal drilling systems automation closer to reality.
Successful Infill Realized through Prudent Brownfield Oil Rim Reservoir Management, Offshore Malaysia
Authors: Khalid Aizuddin , Ahmad Tajuddin Nor Baizurah , Dan Hui Xuan , Sapian Nik Fazril , A'akif Fadzil Nurul Aula , Hassan Siti Normaizan
Published: October 2018

Managing an oil rim type reservoir has constantly been a great challenge and understanding the oil rim movement has remained as one of the main subsurface uncertainties. Prudent reservoir management through an active reservoir, well and facilities management (RWFM) plan is key to realizing the uncertainties, optimizing production and reserves of brownfields. Monitoring the oil rim through cased-hole reservoir saturation logging has been identified as a de-risking method, planned and executed for two consecutive years in the field to minimize the oil rim uncertainty. The field studied is one of the brownfields in offshore Sarawak, Malaysia, which has been on production for more than 40 years.

Results acquired from the cased-hole logs have triggered the need to optimize the location of an infill oil producer planned in the Field Development Plan. The cased-hole results indicated that the original oil target in the N reservoir had mostly been swept by water. Through thorough studies and modeling, an opportunity to the western flank in M reservoir, located close to a proposed workover well, was suggested. Furthermore, latest input on the proposed workover well and facilities health check suggested the workover candidate was not favourable due to its location on an aging single well monopod structure with complex well mechanical problems. Thus, the planned infill oil producer was recommended to replace the workover well and recover the reserves.

Integrated studies incorporated cased-hole results with reservoir modeling indicated that the new infill location would yield a total of 5.7MMSTB reserves with initial production rate of 1215BOPD. In addition, through integration of a multi-disciplinary team, revision to the infill location was timely and the infill was also accelerated from Phase II to Phase I of the development plan as a rig filler for cost optimization. Well test result successfully validated the reservoir productivity of 1238BOPD with no water production.

This paper presents the integrated subsurface and surface solutions and criticality of proactive data acquisition, field monitoring and collaborative team work strategies to maximize the recovery from a brownfield.