bluuebunny/crossref_metadata_2025_split huggingface dataset:
General Isothermal Enhanced Oil Recovery and Waterflood Forecasting Model
Authors: Mollaei Alireza , Delshad Mojdeh 
Published: October 2011

Abstract
Forecasting the performance of enhanced oil recovery (EOR) processes plays an important role in EOR study, design and selection of the best enhanced oil recovery method for a particular reservoir. However, lack of a general purpose EOR forecasting model is unsatisfactory. We address this deficiency by presenting a novel analytical-base general EOR forecasting model that does not rely on conventional numerical simulation.
Using the concepts of segregated flow, material balance and fractional flux (F-C or F-Phi) arrive at a general approach for modeling different isothermal EOR processes including chemical EOR (polymer, surfactant-polymer and alkaline surfactant polymer flooding), solvent flooding (miscible/immiscible, continuous gas flood and WAG) and also waterflooding. We used a Koval flow-storage capacity (F-C) model in the current research because of its strength and wide applicability for both homogenous and heterogeneous permeable media. The validity of the forecasting model was investigated by matching numerous secondary and tertiary field, pilot and simulation results.
History matching showed good agreement between field data and forecasting results. The forecasting model demonstrates a strong ability to forecast the oil saturation, recovery efficiency, cumulative oil recovery, oil cut and oil rate changes with time for secondary and tertiary recovery methods. In addition, predicting the recovery efficiency enables us to generate the volumetric efficiency change with time which is of great importance for studying the EOR processes. These valuable results are produced using a few input variables.
Application Specific Steel Body PDC Bit Technology Reduces Drilling Costs in Unconventional North America Shale Plays
Authors: Hanna Chase , Douglas Charles , Asr Hany , Durairajan Bala , Gerlero Martin , Mueller Levi , Pendse Bhushan , Travers Chris , Bits Smith 
Published: October 2011

Abstract
As drilling activity in conventional land-based plays continue to decline, technology focus is shifting to the unconventional shale gas prospects (Haynesville, Marcellus, Eagle Ford). Efficient and repeatable drilling practices, along with cost effective technologies, are paramount to economically exploit the known hydrocarbon reserves because of the large number of horizontal wells required to develop the vast acreage plays. The drilling challenges include high bottom hole temperatures, high mud weights and hole/bit cleaning issues. The key to reducing field development costs and improving project economics is increasing rate of penetration (ROP) in the lateral interval that typically extends 3000 to 6000ft after completing the build section.
To solve the penetration rate and hole cleaning challenges, an engineering team analyzed the latest polycrystalline diamond compact (PDC) technologies and best drilling practices to achieve the operator's ROP optimization goals. An FEA-based engineering software system was utilized to predict the dynamic behavior of the bit and BHA components in lithologies comparable to the specific field application. To ensure proper utilization of the available hydraulic energy, engineers used computational fluids dynamics (CFD) to ensure appropriate nozzle placement and orientation to effectively clean the bit face and hole bottom. Conclusions from the dual analysis were instrumental in developing new steel body PDC bit designs specifically engineered for emerging North American shale plays.
The new steel body PDC design and the associated bit technologies and updated operating practices have been run in the Bossier City, Louisiana and Tyler, Texas areas with outstanding results. The new PDC technology has increased lateral interval ROP by as much as 80%-100% compared to conventional matrix bodied PDC bits. The authors will present several case studies that document the significant cost savings.
Experimental Results and Analytical Modeling of Solvent-Leaching Gravity Drainage Phenomenon in Heavy Oil Reservoirs
Authors: Ahmadloo F. , Asghari K. , Henni A. , Freitag N. P. 
Published: October 2011

Abstract
Solvent-leaching gravity drainage based processes have gained increasing interest for improving recovery from low-pressure heavy oil and bitumen reservoirs around the world. In these processes, injected solvent in the vapor phase diffuses and dissolves into the oil, hence mobilizing it by viscosity reduction. The mobilized oil drains into a production well under the influence of gravity and capillary forces. In this study, a comprehensive experimental program was conducted to systematically investigate the effects of capillarity and drainage height on stabilized drainage rates in a permeability range of 5.1-6.5D, which is similar to that of western Canadian heavy oil reservoirs. In addition to these experiments, separate investigations were undertaken to measure the capillary pressure of sand packs, as well as phase behavior properties of the oil-solvent system used in this study. The novel design of the experimental setup made it possible to eliminate the effect of pressure disturbances and forced displacement for the duration of the experiments (20-45 days), and investigate the interplay between capillarity and drainage height in the gravity-dominant system. It was found that the observed stabilized drainage rates per unit length of porous media (9.85×10−7-3.44×10−5 cm3/s/cm) are function of drainage height, specific pore surface area of porous media, and concentration of diffused solvent into the oil phase. A one-dimensional analytical model was adapted to calculate the diffusion coefficients for these experiments and develop a new correlation for the prediction of the effective diffusion coefficient in this process. Experimental results and modeling showed that molecular diffusion was the major drive for the mass transfer phenomena in higher capillarities. According to the developed correlation in this study, drainage height, capillarity, and solvent concentration in the oil phase play more important roles in mass transfer phenomenon than those observed in experiments conducted at high permeabilities (&gt;200D).
Evaluation of Fugitive Methane Emission Factor for Oil and Gas in India
Authors: Agarwal Ankit , Singh Ajay K 
Published: October 2011

Abstract
Methane Emissions from the Oil and Gas Industry has been a major Environmental concern for over a long period of time. This work estimates the Methane emissions from the Oil and Gas industry in India. The work has used the guidelines of IPCC (Intergovernmental Panel for Climate Change) which has been a pioneer in bringing regulations relating to environmental concerns. The IPCC guidelines define a two level hierarchical structure for source categories related to the oil and gas industries.
This project aims at estimating the Emissions of Methane from the Industry. For this proper activity data and methodology is required. National activity data in respect of oil and natural gas systems for the years 1990 to 2009 was collected. Methane emissions have been calculated for all the activities listed above. The methane emission factor used for calculating the emissions from the various activities are either used directly from the IPCC or they have been particularly calculated. For activities including oil refining, transportation and storage of oil, gas production, processing, transmission and other leakages default emission factors of Tier 1 Approach of IPCC have been considered.India specific methane emission factors have been evaluated for oil production and venting and flaring activities. This method is clearly defined in the IPCC under Tier 2 approach. The future scope of this work is also to formulate emission factor using Tier 2 Approach of IPCC guidelines for the country. For other ctivities for which some study has already been done and Tier 2 factors have already been calculated in this work, the next work is to implement Tier 3 approach of the IPCC guidelines for continuous monitoring of the emission of methane to the atmosphere.
Keywords: Greenhouse Gas Emission Inventory, Oil and Natural Gas, Fugitive Methane Emission, Activity Data, Emission Factor
History Matching and Production Forecast with Logs, as Effective Completion and Reservoir Managing Tools in Horizontal and Vertical Wells
Authors: Haro Carlos F. 
Published: October 2011

Abstract
Simulation history matching is a daunting, time-consuming task with numerous unknowns and several plausible answers. Scale differences in the data frequently obscure results, precluding its effective application in completion strategies. Good history matching does not guarantee accurate production forecasts. Reliable predictions, required for well planning, depend on our ability to reduce the uncertainties to find consistent and timely solutions. Logs can provide appropriate conditioning data for history matching and to manage the reservoir. We prove it with field data.
Electrofacies, absolute, relative permeability and capillary pressure, imprinted on logs, can be mathematically linked with irreducible water saturation. Logs are at the right scale for completion designs. They facilitate upscaling, honoring rock and fluid properties, and the physics of flow. Logs are snapshot measurements, amenable for conversion into dynamic forecasting tools employing flow and pressure equations. This concept permits creation of synthetic production logs over time, to calculate production decline.
We introduce the integrated utilization of material balance, flow-pressure algorithms, fluid data, cores and logs. We represent every well as a finite, gridded tank, capable of producing measurable volume of fluids, limited by its petrophysical constrains. Superposition, in terms of pressure and flow, combines the various components, within and amongst wells. Quality of the results is ensured, since material balance must withstand at every depth at all times, under different production scenarios and the prevailing driving mechanism.
With this log handling, we help to take strategic economic decisions to maximize reserves and optimize the reservoir development plan. We obtain oil in place, drainage radii, lateral connectivity, fluid bank arrival times, productivity indices, inflow performance, production allocation and recovery per zone, per well, parameters generally not provided by other methods. We streamline completion designs and conformance, the day to day managing of the reservoir, with this refined use of logs.
Production Forecasting with Logistic Growth Models
Authors: Clark A. J. , Lake L. W. , Patzek T. W. 
Published: October 2011

Abstract
With the commercial development of extremely low permeability oil and gas reservoirs, new challenges have arisen both from operational and reservoir standpoints. Reservoir models, which previously yielded reasonable results for reserves estimates and production forecasts, no longer do so. Various new models and techniques have been proposed to improve the accuracy and reliability of reserves estimates; however, none have gained widespread industry acceptance. This paper will propose a new empirical model for production forecasting in extremely low permeability oil and gas reservoirs based on logistic growth models. The new model incorporates known physical volumetric quantities of oil and gas into the forecast to constrain the reserve estimate to a reasonable quantity. The new model is easy to use, and it is very capable of trending existing production data and providing reasonable forecasts of future production. The logistic growth model does not extrapolate to non-physical values.
A Strategic Method To Accelerate Individual's Learning And Enhance Subsurface Team Performance Within Multidisciplinary And Multigenerational Environments
Authors: Dashti Qassem , Gunawan Christine 
Published: October 2011

Abstract
The development of young geoscientists and engineers to be independent contributors is paramount for Kuwait Oil Company's long-term success in optimizing their production and improving field development efficiency. In our fields, the main challenges are characterized by the deep and tight naturally fractured carbonate reservoirs, volatile fluids, high-pressure-high-temperature conditions and the presence of CO2 and sour gas.
Production enhancement activities play a significant role in maintaining production capacity. Therefore, rapid and integrated decisions from multidisciplinary teams are necessary to select potential solutions and to accelerate the required remedial work. Yet the largely junior population of the asset teams creates an immense challenge in getting the work completed.
Overcoming this challenge begins by developing individual staff learning programs that are aligned with competency gaps, business needs and personal development plans. The program lists the competencies required, which are then achieved through blended learning. The learning program emphasizes transferring knowledge and skills on the job, and holds the learner accountable for achieving results. Therefore, linking training with relevant and appropriate task assignments is essential to accelerate and reinforce competency development. One task which has proven key in the blended learning methodology is conducting formal and detailed well reviews, in which all pertinent data is presented on a specific well, and a multi-disciplinary team brainstorms and recommends an action plan and the additional. Staff assigned to conduct well reviews must develop knowledge outside their domain in order to facilitate team collaboration among the different disciplines, allowing the sharing of best practices and optimum decision making.
This accelerated staff development method has been applied for two years in North Kuwait and has resulted in meeting our production goals, better field management and improved team performance. Some examples of activities enabled by this methodology are defining perforation intervals, developing sector reservoir models to determine shut-in periods required for buildup testing, and formulating workover program design. In these two years 12 workover programs have been completed successfully - is an outcome of 66 well reviews. Just as importantly, junior staff competency grew 48%, an achievement which is mainly the result of their being assigned and performing jobs such as well data analysis and well reviews with minimum supervision.
This paper details the method and progress of what has proven to be the best approach to accelerating staff learning curves, reducing competency gaps and enhancing professional development that delivers. Also summarized is the value of team collaboration, interaction between engineers and geosciences for successful reservoir management, and lessons learned.
New Locking Clutch Turbine Technology Successfully Frees Stuck Bit/BHA in Deep Gas Wells, Oman
Authors: Kapoh Oddy , Van De Velden Mark , Al-Hajji Mohammed , Houqani Said , Cook Perry , van den Bos Maarten , Hanna Joseph , Al-Salti Mohammed , Arnott Steven 
Published: October 2011

Abstract
Drilling hard-rock sequences in northern Oman can present a number of distinct challenges. Operations are frequently hindered by formation breakout in rocks with high confined compressive strengths (15,000-50,000 psi). The problem is exacerbated by highly abrasive formations, extreme bottom hole temperatures (160-175C) and the subsequent deterioration of mud properties at vertical depths of approximately 4500-5500m.
The main challenge is bit/bottom hole assembly (BHA) sticking while drilling a tectonically stressed sandstone formation. Formation breakouts that occur at or just above the bit can go unnoticed as drilling progresses and are the main sticking mechanisms responsible for turbine stall. The use of durable impregnated bits and motor/turbine BHA can increase drilling performance. However they bring an increased risk of leaving tools in hole (LIH) because the bit and driveshaft are able to rotate independently of the drillstring in a stuck bit event. A conventional motor/turbine has no reliable mechanism to transfer the available high torque from the drillstring to the bit, leaving axial force (pushing/pulling) as the only means to free a stuck bit/BHA.
For this reason, the operator is exploring new technological solutions to reduce non productive time (NPT) associated with stuck events. A recent research and development effort has resulted in a new-style turbine, which in the event of stalling or bit sticking, locks the bit to the body of the drive-system so that drillstring torque can be applied to the bit. Transmission of drillstring torque to the bit significantly increases the chance of freeing a stuck bit/BHA. And instantaneous locking while rotary drilling can reduce the risk of becoming stuck by keeping the bit in motion should the turbine stall.
During technology trials in 2010 BHAs in nine deep wells were successfully freed after several stuck events. The authors will provide a BHA schematic and the procedural details that contributed to the successful operations.
Integration of Formation Pressure Data to Improve Reservoir Characterization and Reservoir Management in PL19-3 Oil Field, Bohai Bay
Authors: Yu H. , Hallenbeck L. , Hofer R. , Summers L. , Wu C. , Zhang J. 
Published: October 2011

Abstract
The Peng Lai (PL) 19-3 Oil Field, located in the ConocoPhillips operated Bozhong 11/05 Block in the central southern Bohai Sea, offshore China, is currently the largest offshore oil field in China. The trap is a complex wrench anticline developed along the Tanchen-Lujiang fault system. The main oil accumulation is in the Neogene Lower Minghuazhen and Guantao Formations with a vertical relief from the top reservoir to the deepest oil bearing rock of approximately 500 meters. The PL 19-3 Oil Field, deposited in a fluvial environment, is a complex stacking of unconsolidated sandstone reservoirs, with moderate porosity and permeability and low net gross ratio. The trap has been divided recently into numerous fault blocks which have unique contacts and variable oil properties both vertically and laterally, with oil gravities ranging from 12 to 22 API.
This paper reviews the pressure acquisition history and analysis from the 160 well formation test database, which includes both wireline formation test (WFT) and formation test while drilling (FTWD). Formation testing in the Neogene formation of Bohai Bay is challenging since the reservoir is unconsolidated and the oil is heavy. Common problems that affect pressure testing are described, efforts to enhance test efficiency are stated and key learnings and best practices to secure high quality pressure data are summarized.
Conventional pressure interpretation to derive fluid gradient and oil water contacts, identify reservoir compartmentalization and flow barrier is challenged due to small density contrast between the heavy oil and water in the field. The excess pressure method, which is attributed to formation water properties and consistent hydrostatic pressure gradient in the field, has been an effective way to analyze pressure data. In this paper, the historical application of excess pressure in the industry is reviewed, examples of the excess pressure interpretation in PL 19-3 Oil Field are given and integrated interpretation practices are emphasized.
Pressure data have wide application in the PL 19-3 oil field. This paper summarizes and demonstrates how original excess pressure and dynamic logging while drilling (LWD) pressure data have been used successfully to predict oil water contacts, to analyze fault transmissibility, to monitor water flooding efficiency, to identify fluid properties, to interpret fault cuts in wells, to optimize mud weights while drilling and to mitigate risk and well bore damage during completion operations
DTS Sensing: An Emerging Technology Offers Fluid Placement for Acid
Authors: Reyes Robert , Glasbergen Gerard , Yeager Valerie , Parrish Joseph 
Published: October 2011

Abstract
Distributed temperature sensing (DTS) is used on wells to determine the effectiveness of acid treatments. The technology uses a fiber-optic cable to read temperature in real-time, which allows for validation of fluid placement. In the case studies presented in this paper, effectiveness was determined during the pumping of the job. Using this process, the operator was able to decide if a change to the design needed to be made in real-time during pumping. The effectiveness of the acid job was dictated by how effective the fluid was placed into all zones. Concerns related to the acid treatments included where the acid was placed in the well, if the acid went where it was supposed to, and if the acid went into the first least-resistive zone and subsequent zones went untreated. If the latter took place, then investment capital for gallons of acid was not used wisely. The acid treatments included a wide variation of stimulation methods, such as stimulation of the formation using fracturing or matrix rates, varying the acid percentage, varying the type of acid, using linear, gelled, or crosslinked acid, varying the rate, and using diverters. Historically, on acid jobs, surface readings for pressure and rate were the only indicators to judge the effectiveness of the treatment. As the operator attempted the previously mentioned acid treatments and also monitored the treatment using DTS, it was observed that what is seen at the surface can be misleading. This is because surface pressure can be masked by friction and is therefore not a valid indictor for what occurred down hole, and because diversion can take place without surface indication. DTS allowed for practical adjustment to the diversion strategy for the well that was being treated. Candidate selection is highly recommended when using the DTS-number process. Placement of stimulation fluid was and is critical to well stimulation. DTS allowed real-time analysis to determine in real-time if stimulation was effective during the job.