bluuebunny/crossref_metadata_2025_split huggingface dataset:
Combined Analysis of One Tough HPHT Carbonate Gas Reservoirs in China
Authors: Xu Yandong , Pang Wei , Li Shuanggui , Zou Ning , Du Juan , Mao Jun 
Published: February 2017

Abstract
Shunnan Block in North-West China is one of the toughest HPHT gas reservoirs with vertical depth over 7500 m, formation temperature over 200 and pressure gradient varying from 1.3 to nearly 2. The condition is close to temperature and pressure limit of well testing tools, therefore, the tools are hard to be sent to downhole and chances are that well testing operations usually failed. The pressure buildup data are with bad quality and needed to be converted into downhole data. Meanwhile, it's hard to diagnose accurate flow regimes and interprete because the block is typically carbonate reservoirs with porous medium including pores, natural fractures and caves.
In this paper, we reviewed the exploration wells in this block and find that interpretation by pressure buildup or transient production data can only reflect part of the formation information; therefore the two kinds of data are combined to get more accurate interpretation results. For pressure buildup interpretation, three models including dual porosity model, composite model, and dual porosity with composite model are chosen and compared. For the production data, dual porosity model with boundary is selected because the wells usually show characteristics of multiple porous medium and boundary dominated flow. Parameters interpreted from pressure buildup data are simultaneously transferred into the model for production data.
Results show that the combined interpretation by pressure buildup and production data can reduce the un-uniqueness of models as well as enhancing the accuracy of formation and wellbore parameters evaluation. The model and parameters can satisfy both pressure buildup and production data history. Although Shunnan block is considered as one greatly promising reservoir from the short period open flowing, the combined interpretations suggest very limited drainage volume. Reasons for this paradox phenomenon may be that the wells are severe contaminated by drilling fluid, or the wells were only producing gas in caves and natural fractures nearby the wells while other caves are not connected.
Microwave With Assisted Ceramic Materials to Maximize Heat Penetration and Improve Recovery Efficiency of Heavy Oil Reservoirs
Authors: Batarseh Sameeh I. , Othman Haitham A. , San-Roman-Alerigi Damian , Kumaoka Shunichi 
Published: February 2017

Abstract
The objective of this work is to improve microwave heat penetration depth and propagation into the reservoir for maximum recovery. Research has discovered ceramic materials, known as an enabler, with unique properties that when exposed to microwave energy, for short time, heat up reaching 1000°C (temperature can be controlled). In this technique, oil is not directly heated by microwave radiation; rather the ceramic materials absorb electromagnetic energy and covert it to thermal energy; thereby heating up the crude oil, and improving heat penetration depth and propagation into the reservoir.
This paper presents several successful experimental works and proposes solutions to overcome the challenges in producing heavy oil reserves, either associated with using microwave only or steam. Several experimental studies have been conducted in the lab to compare heat penetration depth and distribution in sandstones and limestone samples; the tests were divided into two sets, the first used microwave only, and the other combined microwave with the ceramic material. The result, from all studies, showed there is a significant improvement in heat penetration depth in the rock when combining the microwave with ceramics; therefore proving that this technology can be used for in situ heat generation. On the other hand, using microwave only has limitations that can be overcome with this approach and has the potential to unlock huge heavy oil reserves, especially in deep and offshore reservoirs.
Based on the laboratory results, a numerical model is developed to characterize the optimal heating dynamics as a function of volume and spatial distribution. Next, a method for lab scale simulation of production efficiency using a heavy oil apparatus (HOA) is discussed. The outcome of these studies will be used as an example to develop a field deployment plan.
Field Proven Effectiveness of Near Wellbore and Far Field Diversion in Acid Stimulation Treatment Using Self-Degradable Particulates
Authors: Malik Ataur R. , Asiri Mohammed A. , Bolarinwa Simeon O. , Guizada Pablo H. , Driweesh Saad M. , Buali Muhammad H. , Shammari Nayef S. , Khalifa Mohamed 
Published: February 2017

Abstract
In acid stimulation treatments, acid will enter the most permeable or the least damaged zones. Most of the fluid will flow into the path of least resistance leaving large portions of the formation untreated. A critical factor to the success of an acid stimulation treatment is proper placement of acid so that all productive intervals are contacted by sufficient volumes of acid.
The original stimulation fluid flow was altered to achieve uniform placement of treatment fluids during acid stimulation in candidate wells. Particle bridging technique utilizing self-degrading particulates of multiple grain sizes was utilized to achieve successful diversion and fluid placement across the entire interval of interest. Particle size distribution was calibrated for use with both near wellbore bridging across perforations and far field diversion inside wormholes and natural fractures. For self-degradable particulates to be successful as effective diverter, it should have accurate particle size distribution, therefore, a comprehensive well data analysis performed during design stage to recognize the opportunity for combination of far-field and near wellbore diversion systems for acid stimulation treatment.
The combination of far-field and near wellbore self-degrading particulate diversion systems allowed the entire intervals to be treated evenly under matrix and fracture conditions, which is usually hard to achieve during acid stimulation treatments utilizing conventional chemical diversion systems, especially in cases where separate sets of perforations would need to be treated with a single stage. Evaluation of the diversion effectiveness was done by running temperature log immediately after the stimulation, which demonstrated satisfactory cool down effect across perforation intervals. This diversion technique was found to be more enhanced to effectively acid stimulate in high temperature carbonate reservoirs of Saudi Arabia.
The utilization of self-degrading particulates of various grain sizes for far-field and near wellbore diversions during acid stimulation in high temperature carbonate reservoir was a unique approach and can be further optimized to resolve the challenges of multistage acid stimulation treatments.
Investigation of Relative Permeability Characteristics for Supercritical CO2 Displacing Water and Remaining Oil after Seawater Flooding in Carbonate Rocks at Reservoir Conditions
Authors: Zhou Xianmin , Al-Otaibi Fawaz , Kokal Sunil 
Published: February 2017

Abstract
Supercritical CO2 (sc-CO2) miscible flooding has been successfully used as an enhanced oil recovery (EOR) method in both sandstone and carbonate reservoirs. The sc-CO2 is miscible with the remaining oil left after water flooding at injection pressures above MMP to achieve higher recoveries. During the process of the sc-CO2 injection after water flooding, there are two phases in the formation, a water phase and a miscible phase (sc-CO2dissolve into oil). To describe the flow characteristics and performance of these phase, the water (Krw) and miscible phase (Krm) relative permeability curves are needed in reservoir numerical simulation during sc-CO2 miscible injection. Surprisingly, publications of experimental data that include water and miscible phase are relatively rare due to the lack of proper experimental methods used. Usually, researchers use water and sc-CO2 relative permeability curves instead of water and miscible phase relative permeability to describe the flow characteristics when sc-CO2 displaces water and remaining oil. In this paper, we propose a modified method based on Corey's model to describe water and miscible phase relative permeability using end point values of water and sc-CO2 miscible flooding.
To obtain the end point values from water and sc-CO2 miscible flooding, four core flooding experiments were carried out on carbonate composite cores using live oil at reservoir conditions. These included two short core and two long cores. The Corey's model was used directly to predict oil/water relative permeability in the carbonate composite cores. A modified Corey model (proposed in this paper) was used to calculate water and miscible phase relative permeability and describe the flow behavior of sc-CO2. The effect of the Corey's exponents, Nw and Nm, were evaluated on relative permeability characteristics in the carbonate composite cores during sc-CO2miscible flooding.
Modified Corey model paramaters include the maximum water saturation, Sw(max), remaining oil saturation Sorw and Krw at Sorw from water flooding process, residual water and oil saturations and the maximum sc-CO2saturation from sc-CO2 injection process. The relationship between relative permeability to water and miscible phase vs. miscible saturation has been developed when the water saturation is decreasing during sc-CO2 miscible injection process. In addition, it is an obvious influence of water and miscible phase relative permeability when the Corey exponents, Nw and Nm are changed.
An Approach to Use Refurbished Bits from Previous Wells that Involves Cost Savings and Effective Bit Utilization
Authors: Tariq Bilal , Duran Roberto , Hashmi Atef , Shafeiq Mohammad 
Published: February 2017

Abstract
An inventive application for Roller Cone (TCI) and Polycrystalline Diamond Compact (PDC) bits (all sizes) that involves reusing the bits in future wells for similar well design types. With factory drilling being carried out in one of the Gas field (among other areas in gas) with over 50 runs a year provides an excellent opportunity to utilize rerun bits, both TCI and PDC, that have a 90-95% life remaining. Using this approach provides an effective and efficient way of cost saving during drilling.
While the cost of new bits in the country is very high compared to markets outside, mainly due to logistics issues with recent and continuous enhancements in bit designs, it makes complete sense to reuse these bits; especially when a huge inventory is available due to so many rigs drilling the similar type well designs in one or similar gas fields. The main criterion is to keep a track of all sizes of bits used on all gas rigs in the area and in the tool house (warehouse). Often, a particular size bit, either TCI or PDC, is used to drill a very short interval in a particular section due to a technical reason for the bit in the well being pulled out of hole, and is almost in brand new condition. Having an up-to-date inventory of these bits from the gas rigs, the tool house, and bit vendors makes it easy to identify such bits and utilize them in new wells, which provides significant cost savings.
Using the rerun bit approach immediately takes the bit cost for that particular hole section to 0$ and so we can achieve additional drilling optimization by utilizing a mud motor in that section, i.e., 12-in., 8-3/8 in., or 5-7/8 in., and further increasing the rate of penetration (ROP) by maintaining the same cost/ft ($/ft) in the section and even breaking bit record runs. In the last few wells it has been evident that by using this approach, the cost/ft for the 12-in. section drilling in the Gas Field field is seen as low as 52% of the new bit for the same year; providing a benchmark for the field. This would not have been possible without utilizing the rerun bits from previous wells. This approach is proving to be very beneficial. As a result of a number of these TCI and PDC bits available in reusable condition as a result of a large number of wells drilled every year in gas fields, significant cost savings have been achieved, which translates into millions of dollars in savings.
The rerun bits have substantial advantages over the new bits, primarily due to cost savings and enhanced bit designs with high durability and bit life over the last decade. For particular application in gas drilling, it is clear that having a large inventory of rerun bits available for almost all hole sizes will enable drilling cost optimization.
Emerging High Temperature Well Stimulation Diversion Technology Leads to Significant Increases in Conductivity
Authors: Bestaoui-Spurr Naima , Castillo Dorianne , Debenedictis Frances , Brannon Harold 
Published: February 2017

Abstract
Well stimulation fluids have been shown to improve oil and gas well productivity in both conventional and unconventional formations. Many formations contain multiple producing zones and areas of high and low permeability; therefore, during stimulation treatments, creating and increasing conductivity networks is highly desired. The most traditional method to increase conductivity networks is by diverting well stimulation fluids from high-permeability zones to low-permeability zones. This can be achieved by using various types of materials and techniques such as forming a filter cake that blocks off the high-permeability zone so that the fluid can be redirected to low-permeability zones. A more innovative approach is to use a diverter system made of dissolvable agents with proppants to force flow to the high-resistance path instead of the low-resistance path. The two types of particles are mixed in a way that they block any permeability from high-permeability zone once placed, effectively creating diversion of the fracturing fluid to other areas. Once the agent has provided its benefits and has dissolved, it leaves behind a proppant pack in both the lowand high-permeability zones, providing conductivity that is not otherwise achieveable. The fracture geometry is consequently enhanced by ensuring that the fluid and proppant are able to access all available fracture networks and open perforations. This paper describes an evaluation of two biodegradable particles and their application as diverters and also in combination with proppants for diversion.
Conductivity studies were performed to determine regained conductivity under stress and temperature. The dissolution profiles of two soluble particles and comparison with polylactic acid were also performed in static conditions as function of time, size and type of carrier fluid for individual particles as well as their mixtures with proppant. The conductivity studies showed that once the dissolvable particles dissolved, the proppant pack provides conductivity that is orders of magnitude higher than when only the biodegradable particles are used for diversion. The studies also show that a material with glass transition temperature below the application temperature had better strength for high-temperature application, and each material has a dissolution profile that is a function of the particle size distribution and temperature.
Optimal Management of Topside Diluent Injection for a Heavy Oil Field
Authors: Astutik W. , Hoffmann A. , Rasmussen F. , Whitson C. H. 
Published: February 2017

Abstract
Heavy oil fields can be developed using diluent (light oil, condensate, etc.) injection at the well level as a flow improver. However, diluent can also be injected at the surface, as used in Canadian heavy oil production. Benefits of topside diluent injection include among others (1) improved oil/water separation in the surface processing facility, (2) improved viscosity, and (3) better final crude quality. Such blending activities are often associated with additional OPEX due to the high price of diluent, which can add significant costs to a development. This paper describes an Integrated Asset Modelling (IAM) solution designed to minimize the topside diluent requirement while honouring technical and market crude specifications. The case studied is an offshore heavy oil field consistings of two reservoirs with API gravities of 14 and 12, and oil viscosities at reservoir conditions of 70 cp and 500 cp.
The production facilities include a two-stage surface processing facility followed by a coalescer aimed to separate the water from the crude. Diluent is injected in the surface processing facility prior to the second stage separator. Operating variables include (1) the topside diluent injection rate and (2) the temperature of the second stage separator. The difficulty of the production optimization problem lies in the non-linearity of the process and viscosity models, and the consistency of the fluid’s PVT description throughout the production system.
The proposed optimization solution is coupled with a reservoir simulator to determine optimal topside diluent requirements over time and foresee eventual bottlenecks in the surface infrastructure design. The proposed solution can also be used as a real-time management tool during the production phase to find the optimal operating point based on real-time data. The optimal operating point ensures the lowest diluent consumption while meeting all system constraints, providing the framework for significant cost savings.
Well Test Simulation for Dual Porosity-Dual Permeability Using Orthogonal Collocation
Authors: AL-Muftah Ali 
Published: February 2017

Abstract
This paper presents a new way to numerically simulate flow in Dual Porosity - Dual Permeability system which is solved rigorously with wellbore storage and skin. This paper shows that the use of Orthogonal Collocation method is feasible and that, in many cases, it results in solutions that are more realistic than those resulted from numerical inversion of Laplace transform. There are, however, certain disadvantages. For example, oscillation of the pressure derivative which can be overcome by using Orthogonal Collocation on Finite Element (OCFE) in which programming effort are usually in excess of that required by a finite- difference or numerical Laplace inversion scheme. Even so, it is felt that the potential of the technique is sufficient justification for this work and for a continuing effort to apply it to well test simulation problems.
Dual Porosity - Dual Permeability well testing problem is described by a complex set of nonlinear partial differential equations. Their solution is normally achieved analytically using Laplace transform or numerically through the use of numerical inverting methods of the Laplcace transform like Stehfest and Crump. This paper is an extension to the paper SPE 120668 that introduced the method for the basic well test problem.
The primary objective of this paper is to investigate the feasibility of using Orthogonal Collocation on well test in Dual Porosity - Dual Permeability system. Since this work was primarily concerned with the feasibility of Orthogonal Collocation simulation, no attempt was made to study a wide spectrum of cases of well test problems. However, a few typical applications are presented and some of the results are compared with those derived from analytical and numerical inversion.
Qualitative and Quantitative Impact of Thin Rock Lamination on Acoustic and Geomechanical Properties of Organic-Rich Shale
Authors: Al-Qahtani Adel A. , Tutuncu Azra A. 
Published: February 2017

Abstract
Thin rock lamination is one of unique features that distinguishes organic-rich shale source rocks from conventional reservoir rock formations. The orientation of rock lamination has an influenceon acoustic and geomechanical characteristics of organic-rich shalethat canaffect drilling and stimulation operation decisions.In this paper, the impact of rock lamination orientation was qualitatively and quantitatively assessed.
Core analysis and tri-axial experimental study were conducted on several US shale formations including Eagle Ford, Mancos and Green River. At various stress conditions, rock samples were tested at different lamination orientations and rock mechanical properties (e.g. rock strength, rock failure behaviour, acoustic velocities, and elastic moduli) were obtainedand qualitatively evaluated.
Fromthe tests, horizontal oriented samples exhibited highest maximum compressive strength where the lowest maximum compressive strength was observed at the orientation of 60°. The vertical and horizontal samples displayed a multi-step failure behaviour, resulting in a creation of complex fracture system, whereas sliding failure behaviour was noticed on other orientations. The analysis of Alqahtani's (2015) correlations showed that rock lamination orientation is a controlling factor that needs to be taken into account in estimation of static and dynamic elastic modulus.
Innovative Technology and Advanced Engineering Prove Concept for Future Field Development of an Ultra-HPHT Unconventional Gas Reservoir
Authors: Abbott J. , Eswein E. , Abad C. , Székely-Szabó T. 
Published: February 2017

Abstract
The well X in the reservoir Y of the Z basin comprises several low permeability siltstone reservoirs which require propped fracture stimulation to produce at economically attractive rates. This region is known for an abnormally high geothermal gradient, resulting in bottom-hole static temperatures over 210degC / 410degF. This paper will describe the state-of-the-art technologies and techniques required to successfully complete the well and optimize well and completion design for future field development.
Due to the extreme conditions, new technologies and techniques were required to address key challenges and ensure the success of the project. A novel, state-of-the-art fracturing fluid was successfully applied to ensure fluid stability when faced with temperatures in excess of 210 degC. Tracers and high temperature diagnostic tools were deployed to aid with onsite design changes and later to evaluate fracture geometry and production performance. The onsite execution data was combined with post-job diagnostics and well test data to evaluate well, formation and fracture performance with aim of optimizing well and completion design for new wells in the field.
Three fracturing stages were successfully completed in this ultra-high temperature tight gas well. The key technologies and techniques applied enabled the successful completion of the operation and, more importantly, provided the data crucial for optimizing well and completion design for future wells. The well achieved commercial production rates and provided proof-of-concept for future field development. Advanced production enhancement design workflows have played a key role in optimizing job design, assessing job performance and evaluating the completion strategies required for future field development.
A new ultra-high temperature fracturing fluid was applied for the first time in Europe. The first application of ultra-high temperature bottomhole gauges for reservoir characterization was performed. A reservoir centric fracture simulator was used to design and evaluate fracture performance, production prediction and optimize future well and completion designs.