bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multistage Hydraulic Fracturing in an Openhole Ultratight Sandstone Formation in China—Design Considerations and Execution Results
Authors: Zhou Zongqiang , Li Xianwen , Xu Yonggao , Chong King Kwee , Marshall Eric Jonathan , Zhang BaoNan 
Published: December 2007

Abstract
In the winter of 2005, the first multistage completion in an openhole, ultratight sandstone reservoir of the Dot Three field, China, was successfully completed using hydrajet-fracturing technique. Six propped hydraulic fractures were placed individually at strategically selected locations along two horizontal wellbores.
Many horizontal wells with openhole completions have been drilled in low-permeability sandstone formations. The Dot-Three reservoir is one such case. Many of these wells perform below predicted rates with uneconomical oil production. Until recently, no method existed to effectively fracture-stimulate this type of horizontal, openhole wellbore to optimize production.
Successful proppant placement in the Dot Three field (this field has adopted early-c waterflood pattern) has proved to be extremely difficult in the past. Propped fracture treatments pumped within the past 10 years were not successful and their post-frac production only averaged 1 ton oil/day. Proppant placement problems occurred, and were believed to be caused by simultaneous propagation of very narrow multiple hydraulic fractures.
Past propped fracture treatments were performed on vertical wells and a few multiple fracture treatments on horizontal wellbores. These were only possible inside a cased hole using conventional methods (i.e. perforate, frac, set mechanical/chemical zone isolation, repeat cycle). The resulting treatment efficiency was low and results were not satisfactory.
Because successful development of this reservoir would significantly impact Chinese oil production, another method for fracturing cased, horizontal wellbores and a new method of propped fracture stimulation in horizontal, openhole wellbores was justified.
This paper discusses a hydrajet-fracturing technique that uses dynamic fluid energy (instead of mechanical methods) to isolate treatment fluid flow to a specific fracture point along the wellbore. Final results compared to past fractures using conventional methods and post-fracture production responses of the two experiment wells are also discussed.
Injection Profiling in Polymer Injectors in Daqing Oilfield
Authors: Zheng H. , Liu X.-B. 
Published: December 2007

Abstract
Daqing oilfield is implementing large-scale polymer flooding to increase oil recovery. With the increasing of injection fluid viscosity, some traditional injection profiling methods lost their validity. Three methods developed for polymer injection profiling have been used in Daqing oilfield.
An electromagnetic flowmeter was designed for water/polymer injection profiling in injectors without separate-zone injection mandrel at zones. It can survey in both continuous and stationary modes. It is verified that the logging tool string also works perfectly in Alkaline/Surfactant/Polymer injectors. It has been successfully applied more than 2400 runs for polymer injection profiling.
Oxygen activation tools have been applied for measuring water or polymer flow behind tubing and even casing. The logging tool widely used in Daqing oilfield consists of casing collar locater, a neutron generator, three gamma-ray detectors, and relevant circuits. Its measurement error is less than 5 % in the flowrate range from 20 m3/d (130 B/D) to 400 m3/d (2520 B/D) of flow in the annular space between 73 mm (2-7/8 in) OD tubing and 140 mm (5-1/2 in) OD casing. It is applied 350 runs each year, including 250 runs for polymer injection profiling.
Tracer logging with correlation arithmetic has been applied more than 500 times in polymer injectors. The method utilizes gamma-ray detectors to measure flow velocity after a slug of radioactive tracer has been ejected into borehole. The method is preferred for low-injection separate-zone polymer injectors.
Experimental results and field examples have proved that electromagnetic flowmeter, oxygen activation tool, and tracer logging with correlation arithmetic are suitable for polymer injection profiling in Daqing oilfield.
Validation of a 16-in. Bulk Meter for Allocation Metering
Authors: Al-Sibani Salim , Sequeira Daniel 
Published: December 2007

Abstract
The use of Coriolis based mass flow meters and turbine meters is well known in the oil industry for measurement of bulk fluids (two and three phase) exported from their central processing facilities. Large flow rates and the presences of gas in the flow affect the measurement accuracy and performance of these meters.
A typical solution for the same is to use a large sized three phase multiphase meter as done by PDO in its Amal field. This is one of the first deployments of its kind anywhere in the industry. PDO is pleased to jointly present here with its vendor, Haimo, the results of a verification process that has been carried out on one of its large size multiphase meters capable of handling between 15,000 m3/day to 57,000 m3/day (approx. 90,000 bpd to 340,000 bpd) with a GVF from 0 to 50% (Fig. 3)
The results have produced some impressive comparisons. The presentation shall result in communicating the following to the end users:
Application of Bulk Meter for export flow measurement and allocation metering. Another way of verifying the individual well test meters against an export reference, especially where there are no references available in form of test separators, meter provers or the like.
This paper is a summary of methodology used and the results obtained. It is only a factual representation of the data obtained with some additional analysis as carried out by PDO and its vendor.
The Reliability Problem Related to Directional Survey Data
Authors: Ekseth Roger , Kovalenko Kazimir , Weston J. L. , Torkildsen Torgeir , Nyrnes Erik , Brooks Andrew , Wilson Henry 
Published: December 2007

Abstract
The validity of error model predictions of wellbore position accuracy is highly dependent on the application of rigorous quality control procedures to the survey data. Concern has been expressed within the SPE Wellbore Positioning Technical Section (WPTS, formerly ISCWSA) that failure to apply the necessary operational procedures may be commonplace, raising questions about the reliability of the survey data so generated. Directional survey data that does not conform to its model’s predictions represents a risk in terms of lost production, damage to infrastructure and loss of life.
This paper lists all sources of error, describes internal data checks that are capable of identifying many of them, and highlights those that are missed and which will therefore require alternative QC measures. Real wellbore survey data are used to illustrate how the use of inadequate QC procedures can lead to invalid survey data being accepted as valid.
The paper is the product of collaborative work within the SPE WPTS.
Gas to Wire (GTW) System for Developing "Small Gas Field" and Exploiting "Associated Gas"
Authors: Watanabe T. , Inoue H. , Horitsugi M. , Oya S. 
Published: December 2007

Abstract
A new development concept of marginal gas field and associated gas with a reserve between 10 bcf and 1 tcf is suggested. This concept is called as a Gas to Wire System (GTW), which means onsite power generation by produced gas. Because of no need of transportation of the produced gas, GTW is considered to be high efficiency system with merits from economic and environmental perspective.
Japan Oil, Gas and Metals National Corporation (JOGMEC), Hitachi, Ltd., JGC Corporation, Toyohashi University of Technology, and Arabian Oil Company have advanced the research project on high efficiency of totally 50 % thermal efficiency, low cost and low emission GTW by applying Gas Turbine Combined Cycle System (GTCC). The targets of this project are (1) the development of the new burner which is available both gas and oil (NOx emission &lt;25 ppm for gas, &lt;80ppm for oil/oil + gas, and combustion efficiency &gt;99.9%), (2) the design of the low cost pre-treatment for fuel. The technology (1) would add the cost value of the generator itself and give the GTW system the back-up fuel.
The test facility for the technology (1) was prepared and the design and construction of small model burners was carried out. The result of small model burner test shows low NOx emission for both oil and gas. Investigation of particulate material/soot formation affected by fuel properties and impurities was carried out. Corrosion test equipments were designed and constructed. Process flow of available treatment equipments was composed with consideration for impurities permission levels for gas turbine as the technology (2). The tentative feasibility study was carried out. It shows that GTW system makes a marginal gas field valuable and has less power loss from well to GTCC. The subjects in near future are achievement of each target for the developments, conceptual design of GTW system for selected gas field and the assessment of economical feasibility.
Managed-Pressure Drilling – Recent Experience, Potential Efficiency Gains, and Future Opportunities
Authors: Kozicz John 
Published: December 2007

Abstract
Recent development of Managed Pressure Drilling (MPD) Techniques for use from floating drilling rigs began in the late 1990’s concurrent with the development of 5th generation offshore drilling vessels(1). During this period a number of industry efforts focused on developing "riserless" or dual gradient drilling systems employing subsea mu d return pumping system. One of these efforts(2) culminated with the drilling of a test well in the Gulf of Mexico employing a subsea pump based Dual Gradient drilling method. Additionally, during this period another industry group employed aerated drilling fluid and a closed loop circulating system to drill a pressure depleted well section offshore Brazil from a floating drilling rig (3). While technically successful, these efforts did not result in commercially deployable drilling systems.
Much of the initial industry focus has been on developing MPD methods for deepwater applications, many of the techniques are applicable to all offshore drilling operations and a number of recent applications of Constant Bottom Hole Pressure drilling methods have been employed from fixed installation in both the North Sea and US GOM (4, 5, 6). At the same time both Surface BOP and RiserCap™ equipment configurations (Fig 1) have been employed to implement Pressured Mud Cap Drilling from floating drilling rigs offshore South East Asia.
Intelligent Drilling: A Prospective Technology of Tomorrow
Authors: Hu Qin , Liu Qingyou 
Published: December 2007

Abstract
The system composition, function, and run mode of a new intelligent drilling technology in future are prospected in this paper. The technologies, including drilling, new materials, detection controls, microelectronics, telecommunications, computers, robots and ultramicrotechnique, etc., are integrated into the new intelligent drilling technology in future. The portable, truck-mounted, flexible and full automatic drilling rig with coiled tubing will be employed in this system. In future drilling process, intelligent mini-robots mounted on the drill bit will be used to observe and detect all the downhole parameters and send them back to ground so as to simultaneously finish the logging operation in drilling process; intelligent drilling under remote control will be realized by means of controlling the drilling speed and trajectory of bit; all the drilling operations, such as tripping operation, will be completed automatically by the ground robots according to instructions; the cooperation among global drilling operations will be organized through communication network technology. Therefore, it is anticipated to significantly increase the drilling speed with greatly reduced drilling accidents and cost. Owing to the realization of precise control over well trajectory, the intelligent drilling technology will improve the exploration and development of petroleum and natural gas.
Computing Gas in Place in a Complex Volcanic Reservoir in China
Authors: Li GuoXin , Wang YuHua , Yang FengPing , Zhao Jie , Meisenhelder Jeff , Neville Thomas J. , Farag Sherif , Yang XingWang , Zhu YouQing , Luthi Stefan , Hou HuiJun , Zhang ShuPin , Wu Chuan , Wu JieHui , Conefrey Michael 
Published: December 2007

Abstract
Gas-bearing reservoirs of the YingCheng Group in the SongLiao Basin in northeastern China are hosted in a complex assemblage of volcanic rocks. These reservoirs present a large number of interpretation challenges that have made the evaluation of gas-in-place (GIP) problematic. A fit-for-purpose workflow was developed for one accumulation in this area to provide robust GIP estimates in support of a development decision.
The workflow involves a number of novel techniques developed to address the challenges presented by these reservoirs. Rock typing was conducted through integration of core descriptions with neutron capture spectroscopy, nuclear magnetic resonance logs, and borehole images using a neural network approach. These rock types, characterizing variations in chemistry and rock texture, were then propagated in a geocellular model using multivariate seismic attribute analysis and distribution rules based on volcanic analogues. Porosity and water saturation from an innovative petrophysical interpretation methodology were propagated throughout the model based on these rock types. The distribution of both rock types and petrophysical properties was performed stochastically and a range of potential GIP estimates was developed.
Paraffin Deposition Problems of Mumbai High
Authors: Nagar A. , Mangla V. K. , Singh S. P. , Kachari J. 
Published: December 2007

Abstract
Mumbai High located about 160 km West–North-West of Mumbai city in the Arabian sea on the continental shelf of Western India, is the largest and most prolific oil field in India. It is divided into two blocks i.e. North and South. Two important carbonate reservoirs in Mumbai High are L-II & LIII. In between these two blocks L-III reservoir becomes shaly, which acts as a barrier between these two blocks facilitating independent exploitation of the reserves of Mumbai High North and South fields. The clastic reservoir S-1 sand is free gas bearing and it lies in between L-II & L-III reservoirs. L-III reservoir which is present through out the field while L-II reservoir is hydrocarbon bearing only in the Northern block of Mumbai High. The L-III reservoir is multilayered accumulation with 10 main sub layers. The sub layers are designated from top to bottom as A1,A2-I to A2-VII,B & C. Crude oil in A1 layer in western flank is highly paraffinic in nature having high pour point, wax content & asphaltenes. The wells producing waxy crude oil from A1 layer in western flank have shown gradual decline in production due to precipitation and deposition of paraffins & asphaltenes causing impairment of permeability. Deposition of asphaltene in the reservoir makes the formation oil wet there by reducing the relative permeability to oil. Asphaltenes are not soluble in straight chain hydrocarbons such as Kerosene, Diesel oil and Condensate. A new chemical formulation was developed which was field implemented.
The treatment has improved the well productivity of number of wells. The best part of the technique is the sustained production. Case studies of number of wells has been discussed in the paper.
Formation Pressure Testing while Drilling in Bohai Bay's Challenging Environment
Authors: Hahne Ulrich , Pragt Jos , Venier Martin , Meister Matthias , Tan Jenson , Chunsen Dai 
Published: December 2007

Abstract
This paper describes the experience and lessons learned to acquire logging while drilling (LWD) formation pressure and near-wellbore mobility data in Bohai Bay. This area is known to be difficult in terms of measuring key parameters for reservoir description in conventional wireline logging (WL) programs.
While comparisons between WL and LWD, including costs savings associated with the LWD approach, are common today in operators’ minds, the intangible benefits gained by real-time acquisition of these critical data are often neglected. Incorporating formation pressure testing into the drilling process, on the other hand, creates challenges to perform measurements in a timely manner as well as the need for continuous circulation while testing to ensure wellbore safety.
Formation testing at Bohai Bay is difficult because of the unconsolidated formations and all aspects associated with this type of environment, such as borehole stability, hole washouts, sanding while testing, or lost seals.
This paper describes successful test procedures, like the orientation of the probe into any direction, and discusses test examples from various hole sizes in detail. The key to achieve a high sealing success rate seems to be the ability to control and adjust the pad contact forces against the formation. Analyzing each drawdown sequence in the tool downhole and optimizing the drawdown rate and speed in the consecutive test reduces effects like sanding and improves the overall success rate.
Providing this type of formation evaluation data with an LWD tool allows a continuous approach to data evaluation and decision-making. The ability to measure accurate LWD formation pressure data in a variety of hole sizes represents a significant opportunity for safe and cost-efficient wellbore construction, especially in environments like Bohai Bay.
Preventing Mud Losses and Differential Sticking by Altering Effective Stress of Depleted Sands
Authors: Benaissa Saddok , Bachelot Alain , Ong Seehong 
Published: December 2007

Abstract
Drilling through highly depleted sands can result in a multitude of problems such as lost returns, differential sticking, difficult logging and/or not being able to reach the target depth. Often curing lost circulation can be difficult and costly as a result of associated nonproductive time and escalating mud costs. Remedies such as cement plugs, squeezes, expandable liner and casing while drilling can be costly solutions and are not always successful.
The use of fluid management techniques, team efforts and proper engineering have lead to the development of an innovative approach to prevent problems and avoid the complex processes of curing mud losses and freeing stuck pipe.
A newly developed deformable sealing agent can be added to a water-based fluid at 2 to 4% volume. It is a modified liquid insoluble polymer that is designed to reduce pore pressure transmission by internally bridging the pore throats of the low permeability sands and shale micro-fractures. These bridging and sealing characteristics will help protect the formation where lost circulation may be encountered. This effective bridging enhances the effective rock strength, hence increasing the formation fracturing resistance.
A geomechanical analysis indicates that two mechanisms contribute to the success: (1) The near wellbore region is turned into an altered rock because the particles in the new mud tend to block the pore spaces. Stress analyses using rock mechanics theory indicate that fracturing pressure is increased by increasing the tangential stress around the borehole resulting from the ‘enhanced’ mechanical properties of the altered zone. (2) Because of this blockage, it is envisaged that the near wellbore rock strength is increased. This strengthening effect increases the bulk and tensile strengths of the altered rock and increases the fracturing pressure.
This paper will highlight field case histories supported by preliminary laboratory work and geomechanical studies indicate that mud losses associated with severely depleted tight sands can be reduced with the use of the newly developed deformable sealing technology. Some of the field accomplishments of this "internal mud cake" as a bridging/sealing approach are: improved drilling curve, lower well cost, stable and gauge hole, reduction in mud losses and differential sticking and reduction in NPT
Effect of Formation Modulus Contrast on Hydraulic Fracture Height Containment
Authors: Gu Hongren , Siebrits Eduard 
Published: December 2007

Abstract
Much study has been conducted on the effects of formation Young's modulus and in situ stress on hydraulic fracture height containment in layered formations. It has been well documented that in situ stress contrast is the dominant parameter controlling fracture height growth and that Young's modulus contrast is less important. However, a recent study pointed out that modulus contrast can have significant implications on fracture geometry and proppant placement.1 To expand on this topic further, we consider the combined effects of modulus contrast and in situ stress contrast on fracture geometry. A pseudo 3D (P3D) hydraulic fracture simulator with a rigorous layered modulus formulation is used in this study. The fracture height calculated based on uniform modulus versus layered modulus, under the same in situ stress contrast conditions, is compared.
The results are analyzed and explained, based on fracture mechanics fundamentals as well as the coupled fluid pressure effect in hydraulic fracturing. One important finding is that fracture height can also be contained by low modulus layers. The results from this study can be applied to hydraulic fracturing treatments in formations with moderate to significant modulus contrast. The mechanisms studied in this work could also partially explain some recent results from microseismic or tiltmeter mapping that show more fracture height containment than that predicted by commonly used P3D hydraulic fracturing simulators based on averaged modulus.
New Trend in Oilfield Flow Assurance Management: A Review of Thermal Insulating Fluids
Authors: Wang Xiaolan , Qu Qi , Javora Paul , Pearcy Rick 
Published: December 2007

Abstract
Flow assurance has been one of the major considerations in deep water completion design, where undesired heat loss from production tubing contributes to the formation of gas hydrates and causes the deposition of paraffin and asphaltene materials. Traditionally, controlling annular heat loss has been achieved with the injection of steam, the application of silicate foam, the pressurization of the annulus with inert gas, the use of gelled oil as an insulating packer fluid, and the use of vacuum insulated tubing (VIT). Each of these applications, however, has drawbacks due to either its working mechanism or higher cost associated with the technology.
To secure the insulation of the wellbore and to reduce heat transfer from the production tubing to the surrounding areas, various aqueous insulating fluid systems with superior thermal properties have been developed in recent years. Field applications of these fluids have demonstrated significant reduction in heat loss by reducing conduction and minimizing convection. These thermal insulating fluids have been implemented with great success in over 75 deepwater riser and packer applications in the Gulf of Mexico (GOM) over the last several years. Case histories have demonstrated that installation of these water-based insulating fluids is an effective alternative to conventional insulation options, and is becoming the preferred insulation method in many deepwater projects.
This paper will highlight the evolution of different insulating fluid systems and the field experience with each system. Proper testing methods relevant to oilfield flow assurance will be discussed and testing results for these fluids will be detailed. Field cases in the Gulf of Mexico (GOM) will be summarized and the effectiveness of these fluid systems will be demonstrated.