bluuebunny/crossref_metadata_2025 huggingface dataset:
Express Method to Estimate Target Bottomhole Pressure in Pumping Oil Well
Authors: Khasanov M. M. , Khabibullin R. A. , Musabirov T. , Sokolov S. , Krasnov V. A.
Published: September 2014

Most of the oil wells in Western Siberia using electric submersible pumps (ESPs). Selection of the optimal mode of operation for wells equipped with ESP and selection of proper ESP technologies capable to maintain this mode highly important for effective oil production.

For many fields in Western Siberia the lowest bottom-hole pressure achievable is an optimal well operating mode. It gives maximum flow rate of fluid and oil. However, reducing pressure below bubble point leads to liberation of large amount of free gas in flow. It cause one of the major constraints to reduce the bottom hole pressure – artificial lift technologies limitations for working with a high content of free gas in the flow. That increase significance of the accounting of free gas presence in the flow while analyzing oil production systems, designing downhole equipment, calculating target bottomhole pressure.

Despite the fact that modern software can calculate the characteristics of multiphase flow and take into account the presence of free gas in the well and downhole equipment its influence often underestimated by engineers. Probably due to the complexities of quick multiphase flow calculations and lack of intuitive results, visualization tools which could help for decision-making.

In this paper we propose a set of simple graphical tools (pallet and graphs), and methods for calculating the gas fraction in the well and downhole equipment, target bottomhole pressure, applicability limits of technologies. Tools proposed aims to provide quick operational decisions for production analysis and artificial lift design. The paper discusses the experience of using the tools developed on real fields.
Well Control and Management: Killing Fluids for Oil Fields of JSOC Bashneft
Authors: Karpov Al. A. , Vakhrushev S. A. , Sitdikov M. R. , Zdolnik S. E. , Kuzmin A. M.
Published: September 2014

Today well killing operations form an integral part of routine well control and management. Therefore the essential task is to select an optimum killing fluid for the given conditions which would secure safety of well operations by preventing any entry of formation fluid into the wellbore with no risks of formation damage in the near wellbore zone. At the same time killing fluids should be available on the market, easy to use and readily producible at a wellsite.

The use of water-based killing fluids may result in a very long well stabilization time after the operation and reduced well productivity. The most important factors which affect an oil reservoir are the invasion volumes of a killing fluid, its compatibility with formation waters and hydrophilic minerals in the formation rock.

Most fields operated by JSOC Bashneft are characterized by the presence of highly mineralized water bearing beds in the section with density up to 1.18 g/cc. This water is used as a killing fluid and if necessary can be mixed with fresh water to get a mixture of a certain density for the required back pressure on the formation.

The paper discusses risks of scaling when a killing fluid is prepared and mixed with formation waters from various horizons. Within the scope of this study laboratory tests were performed on core to assess the risks of formation damage and reduced permeability in the result of killing fluid invasion into a reservoir.

Given such geological and engineering conditions the design of killing operations should integrate optimization of killing fluid properties with the use of various chemical agents which would prevent any formation damage and protect well equipment.
Problems of Oil and Gas Production Associated With Gypsum Depositing in the Verkhnechonskoye Oil and Gas Condensate Field
Authors: Chertovskikh E. O. , Alekseev S. V.
Published: September 2014

The article is devoted to the problem of scaling in the Verkhnechonskoye oil and gas condensate field. The history of gypsum scaling in VC Field is briefly reviewed. Presented are results of studies conducted in the oil field conditions to select and justify an appropriate technological solution for removal of the gypsum scale. The gypsum removal technology envisages well treatment with a fluid containing caustic soda. Potential causes of gypsum scaling in VC Field are revealed with reference to results of analyses of the consolidated field database. A theoretical justification of geochemical conditions of gypsum scaling in VC Field is proposed. Wells located in gypsum-scaling risk zones in VC Field are identified. The authors give recommendations concerning development of the gypsum removal technology for VC Field.
How IT Technology is Changing the Established Approach to Safety and Reducing Operational Risks
Authors: Rykov Kirill
Published: September 2014

According to best practices, reducing the occurrence of an undesirable event is possible by organizational and technical changes. Organizational changes are mainly related to the implementation of enterprise policies to reduce operational risks and improve operational safety based on standards BS 8800, OHSAS 18x series, ISO 14x series. Technical changes are mainly associated with modification of old equipment to modern, reliable equipment, and with integration of information systems in everyday business activities. These systems support daily activities through creating an information platform for: communication, violations data collection, dangerous situations, emissions, discharges, etc. Accumulated data is in turn used both for analyzing the current situation and predicting possible progression of events, relying on short-term data passed to the system in real-time mode, historical data on the already occurred accidents, incidents, and the prediction logic.

This review article is dedicated to the changes that IT technologies introduce into the environmental and operational safety. It is explained how to use mobile technologies, 3D visualization and operational work with a significant amount of structured and unstructured data for proper understanding and even predicting events.

As a result, the reader will gain an insight into state-of-the-art capabilities of IT technologies in the field of environmental and operational safety, possible difficulties while integrating them into the business environment, the benefits obtained and the business prospects.
Russian Offshore: Gained Experience and Development Perspectives of the Northern Block of the Caspian Sea
Authors: Svarovskaya M. , Senkov A. , Zolotukhin A.
Published: September 2014

Russia being one of the main feedstock suppliers for the world's power generation has, however, a relatively small experience in modern development technologies for offshore fields. In terms of this fact one of the key projects recently put into a full-scale development phase (2010) is Yuri Korchagin field in the northern part of the Caspian Sea. This area includes several oil, gas and gas condensate fields that are now at various stages of their preparedness for startup. Yuri Korchagin oil and gas condensate field features the whole sequience of modern solutions for exploration, development and production of hydrocarbons and performance of R&D activities.

This article describes main results of implementing the design solutions developed for Yuri Korchagin - the first industrially operated field in the North Caspian. The article studies the effectiveness of the selected development scheme for the oil and gas condensate deposit and summarizes the experience in risks management both for technological (drilling, completion and production) and geological (reservoir data and modeling) issues. The article also describes the challenges of expanding the resource base in the area operated by OOO "LUKOIL-Nizhnevolzhskneft". This information can be useful for updating the status of current offshore development projects. Furthermore, this experience could be very useful in developing fields containing an oil rim.
Development of Carbonate Reservoirs with Complex Trajectory Wells in Republic of Tatarstan
Authors: Akhmetgareev Vadim , Idiyatullina Zarina
Published: September 2014

Research and development in the area of complex trajectory well drilling technologies, including combined with hydraulic fracturing treatment, is one of the first priorities for national and international oil producers, OAO TATNEFT is no exception.

As of 1 January, 2014, in TATNEFT oil fields, 587 horizontal wells and 104 multilateral wells have been drilled, including 421 horizontal wells and 83 multilateral wells drilled in carbonate reservoirs. On the average, initial oil production rates of horizontal and multilateral wells are higher vs. vertical wells, 1.8 times and 2.4 times, respectively. The worst production parameters are characteristic of horizontal and multilateral wells, 77 and 32 wells, respectively, draining the Bashkirian-Serpukhovian formations, which testifies to poor efficiency of horizontal technologies in this type of reservoirs. Of the total number of wells targeting carbonate formations, 11 multilateral and 15 horizontal completions showed good well performance.

The paper presents a number of technologies aimed at improved carbonate reservoir performance through complex trajectory wells. Optimization of development of the carbonate reservoirs in the Pionerskoye, Novo-Elkhovskoye, and Shegurchinskoye fields will allow reducing vertical drilling metreage, thus, saving on well construction and infrastructure cost. It will also result in improved reservoir flow behavior, connectivity, and enhanced oil production. It is deemed that oil production of complex trajectory wells will increase 1.5-fold vs. vertical wells. The offered horizontal technologies will help to achieve uniform oil drainage of heterogeneous formations with different reservoir properties and, increase water-free production of wells through use of expandable well completion systems involving packers and ICVs or water-swellable packers. Calculation made in reservoir models show ultimate oil recovery increase by 8-15%. The Company is planning to commercialize the technologies in the nearest future.
Application of Data Mining Tools for Analysis and Prediction of Hydraulic Fracturing Efficiency for the BV8 Reservoir of the Povkh Oil Field
Authors: Alimkhanov Rustam , Samoylova Irina
Published: September 2014

The technique for selecting candidate wells for hydraulic fracturing and prediction of post-frac well performance using Data Mining tools (neural networks, decision tree algorithm, etc.) is presented. The technique was applied to the BV8 reservoir in the Povkh Oil Field. The reservoir is characterized by the complex clinoform structure.

The objective of the paper is to determine basic criteria for candidate selection and evaluate the effect of different geological and field conditions on the efficiency of hydraulic treatments. To achieve the objective two problems have been solved: Development of classification models (efficient/inefficient hydraulic fracturing treatment);Development of regression models (post-frac fluid rate, water cut, oil rate).

Machine learning algorithms were used in petroleum industry in the past, but neural networks is the most common technique. Eleven models have been built based on six algorithms. A comparison has been made between the models. A good consistency between predicted values of post-frac fluid rate and water cut and actual results has been revealed.

Major geological and field criteria for the efficiency of hydraulic fracturing operations have been identified. The models built can be applied to predict the post-frac performance of a single well as well as to do a quick estimation of the whole well stock. The results presented show significant predictive power of the Data Mining tools for geologically-complex reservoirs. It should be assumed that the usage of the technique for less complex reservoirs will allow us to significantly improve prediction of well performance.
Successful Placement of Cement Plugs in HP/HT Wells Using an Innovative Computer-Aided Simulator
Authors: Guo Y. , Zhang X. , Taoutaou S. , Li T. , Li Y. , Lian Y. , Huang S. , Peng Y.
Published: September 2014

Placing cement plugs in high-pressure/high-temperature (HP/HT) wells represents a big challenge, from the standpoint of both the chemistry and the placement techniques. Any failure to properly place a cement plug will lead to costly nonproductive time and will require repeating the job, which represents even more technical and operational challenges because of the downhole uncertainties.

West China's Tarim basin experienced these challenges for HP/HT sidetrack, plugback, loss circulation, and abandonment cement plugs, with wellbore depth over 6500 m and bottomhole temperature over 160 °C. To improve the success rate of placing cement plugs, thorough analysis of well information was done, and novel placement software was implemented to help ensure a successful placement.

The new computer-aided model is a risk-based model that takes into account the downhole well conditions to analyze and display the fluid interfaces of mixing, both while traveling inside the pipe and in the annulus. The result is the assessment of the possible contamination of the cement slurry after pulling the pipe out of the hole and a recommendation for the best fit to execute a successful cement plug. The results obtained with the new engineering tool and precise operational field executions allowed the operator to execute more than 80 cement plugs successfully from 2010 to 2013.
The Twilight of Energy Abundance
Authors: Archibald David
Published: September 2014

The discovery of the giant East Texas Field in 1930 started a period of inherent oversupply of oil that ended in 2004. The oil price has tripled since 2004 while conventional oil production has remained static. Production has not been able to respond to the price signal provided because it is constrained by geological factors. Logistic decline plot analysis indicates that the world consumed half its conventional oil endowment by 2005. Ten years later, production is on the cusp of a long decline at a rate of 1.5 million barrels/day/annum. OPEC production will start declining later than non-OPEC production with both at 27 million barrels per day in 2030, 27% lower than the current plateau level. Tight oil production in the US is expected to peak at about 4 million barrels per day in 2018. A contribution to supply from tight oil production elsewhere in the world will be delayed due to geological, cost and regulatory factors. The price response to the contracting supply of conventional oil will lead to price-driven substitution of liquid fossil fuels by natural gas and synthetic fuels from coal, in turn enhancing the economics of nuclear energy in the electric power market. World coal production will peak in 2021 due to the peak in Chinese production that year. Ultimately the level of civilisation humanity will enjoy will be dependent upon the cost of nuclear power and the production of synthetic liquid fuels using hydrogen electrolysed from water and carbon from farmed sources.
A Cross-Link Polymer Sealant for Curing Severe Lost Circulation Events in Fractured Limestone Formations
Authors: Al-Azmi Bader , Al-Mayyan Haitham , Al-Saleh Fawaz , Godara Vijay , Panchal Rakesh , Kosandar Balraj , Tobeh Samir , Jadhav Prakash , Yadav Prahlad , Samir Ahmed
Published: September 2014

Preventing and curing fluid losses in limestone formations is one of the most challenging loss situations to prevent and control. Loss zones are unpredictable, due to large vugular zones and extended and connected fracture structures. Often these limestone intervals are depleted reservoirs. Typically, calcium carbonate pills containing various size distributions are part of the lost circulation armory in reservoir sections. However, results are highly variable and not suitable for large-scale losses. This is distinguished for those situations with the most-severe lost circulation, where chemical sealants may be more applicable than treatments by plugging particles.

The paper discusses about use of a cross-linking polymer fluid treatment that enables operators to cure lost circulation zones in many different applications, providing distinct operational and economic advantages over conventional reactive and temperature activated methods.

The paper discusses the customization of the polymer fluid to have specific thickening or setting time so this loss circulation fluid can be pumped through the existing bottomhole assembly (bit nozzle size greater than 14/32nd) without losing rig time associated with tripping and mixing conventional loss circulation material treatments (LCM). The paper discusses the execution procedures and cautions to be followed to improve cross-link LCM plug placement as well as chances to arrest losses.

Due to biodegradable nature of organic cross-linking polymer plugs, it was used in sensitive reservoirs with minimal effect on the formation. The cross-linked plug or pill, with time and temperature, will break back to a fluid state and may be produced back and circulated from the wellbore.

The discussions in this paper will further reveal the workings and applicability of cross-link polymer fluid to lower costs for drilling fluids, cementing and casing design.
Reinforced Composite Mat, a Proven Solution for Lost Circulation Control in Sumatra Field
Authors: Pasteris Mathieu , Taoutaou Salim , Simanjuntak Andre , Kusumawatie Reny
Published: September 2014

DESCRIPTION

One of Indonesia historic oil producing field in the Sumatera Island is constantly developed in order to maintain production at a sustainable level. The number of wells drilled is between 250 and 400 per year due to the highly depleted nature of the field. One of the main issues that jeopardize the drilling efficiency in this field is the challenge of drilling and cementing under losses; this can result in a poor cement job quality and/or not being able to bring cement up to surface. A bad zonal isolation can cause loss of steam efficientcy, excessive water production and loss of well integrity requiring costly remedial jobs yielding delayed production since the heavy oil reservoir in this area is produced using the enhanced production technique of steam flooding

APPLICATION

A solution implemented to cure the losses during the drilling and cementing consists of a newly developed reinforced composite mat fiber and granule based loss circulation solution coupled with a diagnostic computer aided software. The Software validates the efficiency of the pill design in curing the losses while drilling and/or cementing. A total of 50 wells were treated, this technology was used in 48 wells while cementing and 2 wells while drilling with a high success rate.

RESULTS OBSERVATIONS AND CONCLUSIONS

This paper will first detail the standard techniques that were used historically in order to combat losses while drilling, then will describe the new approach using the reinforced composite mat technology, and shows quantitative results achieved mitigating lost circulation challenges and ensuring competent zonal isolation which led to eliminating remedial work in more than 60% of the wells.

SIGNIFICANCE OF SUBJECT MATTER

This innovative approach has increased success rate in bringging cement back to surface during well construction on the first attempt from 2% with conventional techniques to more than 60% using Composite Mat Fiber Technology.
Geomechanical and Reservoir Integrated Hydraulic Fracturing Optimisation for a Tight Oil Reservoir: A Case Study from Offshore Vietnam
Authors: Rahman Khalil , Gui Feng , He Wei
Published: September 2014

Producing tight oil reservoirs by hydraulic fracturing is especially challenging due to relatively low oil mobility. At the planning stage, an integrated approach is essential to optimise fracture parameters using a reliable geomechanical model and reliable reservoir simulations to predict the post-fracture productivity and the net present value (NPV). This paper presents such an integrated case study. The reservoir contained relatively clean sandstones interlaying only a few thin shale layers. A relatively low recovery was expected to yield a good positive NPV because production was planned using a nearby existing production facility.

A geomechanical model was built using core, well log and drilling data characterizing the in situ stress, pore pressure and rock mechanical properties in the field. The reservoir properties were characterized from core-log calibration and PVT data from analogue reservoirs. The initial reservoir pressure was very close to the bubble point pressure. Thus, multiphase reservoir simulations were essential to predicting post-fracture production profiles.

The study integrated geomechanical modeling, hydraulic fracturing design, reservoir simulations and economic assessments to investigate various well completion scenarios. Various scenarios included a single vertical fracture in a deviated well, an un-fractured 1,000 m horizontal openhole well and a 1,000 m horizontal well with multiple transverse fractures. The un-fractured horizontal openhole scenario required a life cycle wellbore stability assessment. The fractured horizontal well scenario required the optimisation of transverse fractures and their spacing. The production constraints included a 600 psi tubing head pressure, a maximum oil flow rate of 5,000 bbl/d and a maximum 5-year production period with preference for more accelerated recovery.

The results from this integrated scheme enabled understanding of the impact of various well completion scenarios on decision-making based on technical and economic issues. The lessons learned in the study can be a guide for optimal development of the target field and other similar fields.
A Novel Workflow of Density Log Normalization for Coalbed Methane Wells: A Example from the Surat Basin in Australia
Authors: Ren Bin , Zhang Ming , Cui Zehong , Li Chunlei , Xia Zhaohui , Gan Thomas , Lau Hon Chung
Published: September 2014

In coalbed methane (CBM) projects, conventional log such density has been used heavily for coal identification, coal property derivation and also potentially for coal ranking. This paper presents a novel workflow of density log normalization for CBM wells. It addresses two major challenges to current normalization methods, namely, absence of a pervasive reference layer, and removal of geological effects after normalization.

To overcome these disadvantages, the proposed workflow undertakes six steps, which are data quality control, geological area segmentation, sub-area type well selection, density control points, variable linear transformation and quality control of log normalization results using box plots, matrix crossplots and histograms. This workflow removes the systematic errors caused by acquiring logs at different times with different logging instrument from different vendors. Furthermore, it possesses the advantages of automated quality control, Type Well Method and Reference Layer Method without incurring their respective disadvantages. It has been applied successfully to about 600 wells in the Surat Basin of Australia.

Proper log normalization will reduce the uncertainties involved in geological modeling and increase the accuracy of reservoir evaluation. This paper should therefore be of interest to petrophysicists and geologists involved in CBM field characterization.
Integrated Analysis of Shale Gas Well Production Data
Authors: Stewart George
Published: September 2014

In this paper the analysis of production data from shale gas wells will be considered and a workflow for the treatment of such data will be described. The methodology is based on a mechanistic model of a horizontal well with multiple hydraulic fractures and the data is analysed in terms of an average fracture half length, xf, an enhanced reservoir permeability, k, and the generated stimulated reservoir volume (SRV). Once the analytical model has been fitted to the measured pressure-rate data an advanced forecast, based on specified scenarios for the flowing bottom-hole pressure (or the wellhead pressure), is made which can be used to compute the expected ultimate recovery (EUR) over a given time frame. The integration with other sources of information commences with a review of the fracture design which will have been carried out on specialist software using rock mechanics data from acoustic logs and minifracs. The comparison of the measured transient productivity index for linear flow with that based on the fracture design parameters allows a rigorous assessment of the efficiency of the stimulation treatment. The effect of stress on formation permeability can be an important issue in the understanding of shale gas wells and an optimised choke setting strategy will be required if the effect is significant. It is shown how repeated well shut-ins (termed investigative build-ups) can be used to identify the stress effect and calibrate an appropriate geomechanics model such as the one proposed by Palmer and Mansoori. The mechanistic software can then predict future production including the observed stress effect. A new concept of pressure dependent skin is also introduced to model the deterioration of the conductivity of the major hydraulic fractures.
Source Rock Stimulation: Does This Require More Art Than Science?
Authors: Lehman L. V. , Andress G. R. , Minner W. A. , Mullen M. J.
Published: September 2014

This paper discusses many of the best practices that have evolved through the processes of developing unconventional resources around the globe. The previous phrase is simply a marketing term that describes the practice of completing a formation that was historically considered to be a hydrocarbon source for reservoirs above or sometimes below the actual horizon. Many operators believe that they can seek and eventually use analogous basin case studies to develop their assets when in fact basic data sources can be utilized to develop a completion plan. Total organic content, reservoir pressure, stress regime and brittleness versus ductility values are essential for effective stimulation and ultimately field development for source rock development.

Our case studies focus on the initial field development processes for Bakken, which allowed the development of a neural network model; Eagle Ford, which helped to determine best-reservoir diagnostics for staging and stimulation type; and the Bone Springs play in the Delaware Basin, which has become a target for liquids seekers. The case histories outline data sources useful for new emerging plays as well as examples of pitfalls to avoid.
Vibration Wave Communication-Realise Remote Control for Zonal Production
Authors: Lichen Zheng , Fuchao Sun , Xiaohan Pei , He Liu , Deli Jia
Published: September 2014

Downhole data transmission is a key technology for oil industry. Traditional methods to realize selective zone production were mainly based on cable or pressure pulse technology and the application scale is limited because of their deficiencies. Downhole vibration wave communication realizes digital signal transmission through tubing or casing, vibration wave is used as carrier wave which is modulated by digital signal before transmission, characterized by low cost, simple operation, it will be used widely in the future. In this paper, the transmission characteristics of tubing and the attenuation rule of tubing are studied by a series of experiment & analysis. According to the findings above, a new digital signal transmission strategy was proposed, that is, three or more carrier waves will be used in series during the vibration wave signal transmission in order to avoid the notch wave band of tubing, at the same time, Manchester coding of digital signals and OOK modulation method of vibration wave were developed. A new vibration signal generator was developed based on magnetostrictive material, a new actuator controlled by vibration sensor was developed based on three degree of freedom sensor together with the tubing or casing, which form a new generation of downhole communication system. A new selective zone production system remotely controlled by vibration wave has been developed based on the above system and is under testing now.
Probabilistic Reservoir Property Modelling Jointly Constrained by 3D Seismic Data and Hydraulic Unit Analysis
Authors: Emami Niri M. , Lumley D. E.
Published: September 2014

We present a new method for seismic reservoir characterization and reservoir property modeling based on an integrated analysis of 3D seismic data and hydraulic flow units, and apply it to an example of a producing reservoir offshore Western Australia. Our method combines hydraulic unit analysis with a set of techniques for seismic reservoir characterization including: rock physics analysis, Bayesian inference, pre-stack seismic inversion and geostatistical simulation of reservoir properties. Hydraulic units are geologic layers and zones characterized by similar properties of fluid flow in porous permeable media, and are defined at well locations based on logs, core measurements and production data. However, the number of wells available for hydraulic unit analysis is often extremely limited. In comparison, the lateral coverage and resolution of 3D seismic data is excellent, and can thus be used to extend hydraulic unit analysis away from well locations into the full 3D reservoir volume. We develop a probabilistic relationship between certain 3D seismic data attributes and the hydraulic units we determine at well locations. Since porosity and permeability distributions are estimated for each hydraulic flow unit as part of the process, we can use the 3D seismic probabilistic relationships to constraint geostatistical realizations of porosity and permeability in the reservoir, to be consistent with the flow unit analysis. Reservoir models jointly constrained by both 3D seismic data and hydraulic flow unit analysis can therefore help to improve the accuracy of dynamic reservoir flow simulation and production history matching.
Integrated Production Modelling of Gas Condensate Field
Authors: Bartolomeu Mayembe , Abdrakhmanov Adkar
Published: September 2014

Liquid hydrocarbon production from a gas condensate field has been maximized by integrating the different parts into a single platform. The models integrated are, reservoir, wells, pipelines and surface processing model. With all models integrated, system bottlenecks have been identified and the whole production chain has been maximized on liquid hydrocarbon production.

Different production strategies and recovery mechanism such as Vaporizing Gas Drive (VGD) and Condensing Vaporizing mechanism (C/V) have been applied by gas cycling to enhance condensate recovery. For different production strategies an optimum condensate production has been found.

During pure depletion, most of the condensate has been trapped. Gas cycling has increased condensate recovery.

The best development strategy that maximized condensate production included pure depletion for the first 600 days, partial gas cycling from 600-2750days, full gas cycling from 2750-4250days followed by blowdown from 4250-5480days. For this strategy condensate recovery was 61%.

The process simulator includes the wells, pipeline and surface processing. In this case a production network application has been avoided by including the wells and pipelines in the process simulator.

Detailed steady state surface processing has been modelled for sales gas, lean gas injection, and Liquefied Natural Gas (LNG) plant and condensate production. For each reservoir time step, output process products have been obtained.

This single platform has given more realistic predictions than standalone models. It assists with decisions making, cost saving and long term forecasting.
Wellbore Stability Modelling for Horizontal and Multibranch Lateral Wells in CBM: Practical Solution to Better Understand the Uncertainty in Rock Strength and Coal Heterogeneity
Authors: Puspitasari Ratih , Gan Thomas , Pallikathekathil Zachariah John , Luft Joao
Published: September 2014

Arrow Energy has engaged in drilling production Coal Bed Methane (CBM) wells in the Bowen Basin. As part of its field development strategy, varied styles of horizontal wells have been planned and executed along the coal targets of Moranbah Coal Measures (MCM). Some of the recently drilled multi-branch lateral and horizontal wells experienced different drilling challenges and production performance. Potential geomechanical issues such as borehole conditions and fines/solid production are directly related to wellbore stability during and post drilling.

As part of Arrow subsurface modeling strategy, the project has embarked a detailed Geomechanics study in Moranbah Gas field. The main objectives were aiming to: (i) optimize the mud weight that is required to stabilize the borehole, (ii) understand how specific coal targets respond to the induced stress concentration around the wellbore during drilling and, (iii) capture the vertical and lateral mechanical heterogeneity within specific coal seams. This paper focuses on practical solutions to model the borehole stability, in particular of the uncertainties in the rock strength modeling and coal heterogeneity.

This innovative workflow coupled with geostatistical approach of rock strength and insitu stress with depth-of-damage is first of its kind in CBM environment. Borehole collapse depth-of-damage (DoD) concept is then used to assess risk associated to the volume of yielded rock as a percent of borehole size. The higher the percentage of DoD, the higher the risk of producing excessive cavings. It provides more confidence in optimizing drilling mud weight for CBM horizontal wells by allowing a more scientifically-sound and practical solution to address rock failure mechanisms associated with borehole instability.
The US Shale Gas "Revolution": A Review of the Production Performance and Geology to Establish Potential Economic Benchmarks for Australia
Authors: Starkey A. P. , Katelis Z. G. , McGhee P.
Published: September 2014

Shale plays have created the current natural gas boom in the United States (US) and according to the national Energy Information Administration (EIA, 2013)49 produced 47% of total daily production by the end of 2013 (approximately 31.8 Bscf/d). Extensive production data from thousands of wells are now available for analysis to provide potential benchmark information for the Australian shale gas industry, which is still in its infancy.

This paper focusses on analysis of publicly available US production data from horizontal wells in five depositional basins reported for the Barnett, Eagle Ford, Fayetteville, and Haynesville shale plays. Type-wells are evaluated which allow estimation of a range of representative initial gas production rate and technical Estimated Ultimate Recovery (EUR) characteristics. The analysis also results in generic recommendations for the minimum sample size and duration required for statistically significant well appraisal programs in shale plays. Such activity phases' primary objective should be to efficiently obtain reasonably reliable type-well performance indicators. The US shale plays' experiences to date provide insight concerning this aspect.

Variability in geological factors including, but not limited to: stress regime, total organic content, thermal maturity, porosity, brittleness, natural fractures, and reservoir pressure can result in production performance that differs substantially both within and between shale plays. Also affecting performance is how the wells are completed. The geology of shale formations is discussed along with recent Australian operational activity, geomechanical considerations, and example economics. Analyses of the US data provide potential technical and economic benchmarks for preliminary comparisons to be made with Australian information, and may help to demonstrate the economic resilience required for exploitation of prospective shale gas resources.

However, it must be recognised that the likely performance characteristics of the prospective Australian shale plays' type-wells are not currently well understood due to lack of data. Significant exploration and appraisal activity is needed to augment the extremely limited shale gas well performance data available in Australia to date.
Achieving Operation Efficiency and Enhancing Production in a Brownfield with Multizone Gravel-Packed Intelligent Completions: Two Case Studies from Malaysia
Authors: Atkinson W. R. , Ceccarelli T. U. , Zabala J. J. , Khalis A. , Razak F. , Yildiz R. , Gil J. , Raw I.
Published: September 2014

The aims of every oil & gas operator to optimize production, increase oil recovery, and minimize operating cost are driving the industry to look for innovative completion and production solutions. This is true for brownfields where operators are looking to rejuvenate reservoirs that still have reserves in place as original completion efficiencies deteriorated over time.

A workover and new well offshore Malaysia was conducted in a field to recover oil from a multilayered, high water/oil contact reservoir. The objective was to increase production and recovery volumes in a cost-effective way and reduce rig time. The original completion designs in the field lacked the ability to control and choke the flow from each zone independently, and thus could not optimize comingled production and water cut, resulting in limited oil recovery from the reservoir.

For this reason, an intelligent completion with downhole variable flow control valves and real-time pressure and temperature gauges was considered. The objective was to design an intelligent completion that is both cost effective in a marginal field and that can fit inside a cased-hole wellbore that requires sand control. Because of the many challenges faced in combining the multizone gravel-pack system and the intelligent completion components, both had to be re-engineered to allow for a perfect interface. This resulted in the first intelligent completion installation inside a shunt-tube gravel pack with multizone packers and subsequently future wells with same design.
An Innovative Solution to Accurately Address Water Detection in Subsea Wet Gas Conditions and Provide Accurate Condensate Gas Ratio (CGR)
Authors: Pinguet B. , Gosset P.
Published: September 2014

In wet gas business, the subsea oil & gas industry are struggling with the fundamental challenges to detect either condensed water or first formation water entry. This need is related to the flow assurance concerns, mitigation process with chemical injection, and detection of water breakthrough but beyond that, there are also challenges of custody transfer, fiscal allocation, and associated biases introduced to measurement devices by the change of fluid properties.

In recent years, operators have requested multiphase and wet gas meter manufacturers to solve these challenges by additional measurement and specifically the ‘salinity’ measurement (i.e. conductivity). Most of the manufacturers have responded by incorporating additional sensors into their conventional meter, which address the fundamental problems that their technology faced to correct the bias, but unfortunately, it is also increasing the entire equipment cost.

This paper is describing the development of the most innovative standalone solution to obtain this measurement without necessary the need for a subsea multiphase or wet gas meter. This versatility in the installation of the sensor is becoming an enabler for some oil and gas operators that can obtain a very cost effective solution in some development where a meter is not a requirement.

The paper is explaining the fundamental principle, and the entire process of qualification encountered over 4 years for obtaining a commercial solution including for high pressure and temperature conditions. The performance of the conductivity measurement will be check against the best flow loop references around the world.

The paper demonstrates that even in control conditions with only few tenth to hundredth ppm of liquid (0.001%), it is possible to discriminate the different phases, even the condensate formation inside the pipe (crossing the dew line). This innovative solution is a breakthrough for any wet gas development where flow assurance is critical.
Fleet-Wide Compressor Optimization
Authors: Cowan Adrian
Published: September 2014

In natural gas gathering applications, maintaining the lowest possible suction pressure can provide a significant production advantage. As fields fluctuate and, over time, decline, compressor optimization must be done on a regular basis in order to minimize suction pressure, while maximizing throughput and maintain high levels of overall fleet utilization. This paper gives an insight into the key tools and reports used by natural gas producers in order to manage and optimize fleets of compressors ranging in size from 5 to more than 1000 compressors.

Background into the key principles of compressor optimization and limitations are covered, while detailed compressor performance curves and pressure/temperature set-point start-up packages are used to explain optimizing for maximum throughput in order to: Increase running speedReduce added cylinder clearanceOptimize suction pressureDecrease recycle set point

To fully optimize a natural gas compressor fleet, tools and reports must be used in order to holistically consider the capacity and throughput requirements of each compressor, plant, field and area within an organization. To accomplish this, natural gas producers are implementing tools that provide statistics for easy identification of production and maintenance opportunities across an entire compressor fleet. Explained in this paper are the benefits of using Fleet Mapping Tools, Fleet Management Reports and Plant Potential Capacity Curves.

In a case study with Australian gas producer Santos Ltd, long-term tracking and analysis of detailed performance data was critical to achieving improved fleet utilization. Specific detailed cases illustrate how, over a period of more than four years, Santos Ltd. demonstrated a fleet-wide performance improvement of more than 7.5% in utilization across a fleet of more than 100 units.
Low Salinity Fines-Assisted Water-flood: Analytical Modelling and Reservoir Simulation
Authors: Zeinijahromi A.. , Borazjani S.. , Bedrikovetsky P.. , Rodrigues T..
Published: September 2014

We discuss the fines-assisted case of low salinity water flooding, where the incremental recovery is achieved by induced fines migration, the straining decelerates the injected water with the consequent increase of sweep efficiency on micro and macro scales. The two layers cake reservoir with contrast permeability is discussed. The main idea is displacing of oil by slug of low salinity water with high salinity drive. The displacement occurs first from the highly permeable layer with it's plugging by released fines with the following displacement from low permeable layer by water drive. In this case, no formation damage is induced in low permeable homogenous layer, avoiding the oil production decrease due to induced permeability damage in the low permeable layer. The sensitivity study of with respect to the slug size is performed. We show the competitive effects of fines migration on sweep enhancement and on oil production deceleration. The minimum slug size for low salinity water providing higher recovery if compared with normal water-flood has been found.
Identification of Strike-Slip Faults Provides Insights into the Further Development of Mature Cooper Basin Fields
Authors: Grant-Woolley L. , Kong A. , Schoemaker B. , Nasreddin H. , Montague E.
Published: September 2014

Newly acquired full azimuth 3D seismic in conjunction with modern azimuthal acquisition and processing, and a fresh review of the regional structural model, has enabled the identification of strike-slip faults with greater certainty. Strike-slip faults are often difficult to identify in traditionally processed seismic due to the lack of vertical displacement. The resulting improvement in structural detail in the geological models has provided a better match with well production, performance and reservoir connectivity in mature Cooper Basin fields. The structural interpretation is independently supported by Pressure Transient Analysis (PTA) and image log data in one of the fields.

Field examples are used to demonstrate the observed relationship between strike-slip faulting and hydrodynamic connection. Pressure data supports that fields previously thought to be separate are demonstrated to be connected via strike-slip corridors. Therefore, hydrodynamic disconnect occurs across strike-slip faults. An observed relationship between underperforming wells and proximity to interpreted strike-slip faults is also discussed.

The integrated approach combining new full azimuth 3D seismic data with regional structural concepts, well performance and dynamic behaviour has led to the identification of new development and appraisal opportunities in several mature fields. Application of this multidisciplinary approach, including the structural model, seismic interpretation and analysis of dynamic data is recommended for all fields throughout the Cooper Basin with suitable full azimuth seismic data. This process should be embedded in future field development plans.
Combining Managed Pressure Drilling and Advanced Surface Gas Detection Systems Enables Early Formation Evaluation and Enhances the Drilling Efficiency in a Deep Gas Exploratory Well in Saudi Arabia
Authors: Garrido Cruz Raul A. , Muqeem Muhammad A. , Alghuryafi Ahmed M. , Duran Roberto C. , Hadj-Moussa Ayoub , Mazouz Cherif M. , D'Souza Steve Austin , Aloudat Rami
Published: September 2014

Saudi Aramco recently drilled a gas well using Managed Pressure Drilling (MPD) as part of its exploration program. This well was the third exploratory well drilled with the objective to test the hydrocarbon potential of the sandstone reservoirs of Lower Permian era. Since a narrow drilling window between the reservoir gradient and the fracture gradient was expected, Constant Bottom-hole Pressure (CBHP) variant of MPD was planned to be utilized in this well.

There was no Nonproductive Time (NPT) during the MPD phase, hydrocarbon gas from the target formation was measured by the Gas Chromatograph (GC) and properly circulated out via the Automated MPD Control System without the need of conventional well control procedures. Average Rate of Penetration (ROP) increased by three-folds compared to the nearest offset well. Based on the real-time GC analysis, four zones within the target hole section show the most potential for hydrocarbons and further delineations are being planned for these intervals.

This paper summarizes Saudi Aramco's experience gained during the drilling of this well. It further highlights the operational complexity and the challenges faced during the implementation of this technology while drilling the exploratory well with very little offset information.

The paper also elaborates on the lessons learned and how they were implemented continuously with regards to Health, Safety and Environment (HSE) during the MPD operations. It is concluded that the use of an Automated MPD control system integrated with GC in Saudi Aramco's deep gas drilling project represents a technological improvement that will enable the company in achieving its goals in a safer and a more efficient manner.