bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Interference Test Coupled with a Drawdown Analysis of Horizontal Well using a Multi-phase Flow Meter to Evaluate Reservoir Parameters and Connectivity
Authors: Al-Farhan Farhan , Gazi Naz , Al-Humoud Jamal , Tirkey Naween , Haryono Rafiq 
Published: November 2012

Abstract
Interference testing, although primitive in terms of its introduction and idea to the petroleum industry, still stands to this day as one of the most cost effective and efficient ways of confirming communication and evaluating reservoir properties between wells. Similarly, a pressure build-up is one of the most accurate ways of estimating dynamic reservoir parameters surrounding the well, providing that the shut-in of the well is allowable. On the other hand, a drawdown test is not usually recommended due to the instability of the flow rate, and hence, the uncertainty in the parameter estimation when analyzing the transient of the pressure drawdown. In this project, due to production constraints a drawdown test was run for the active horizontal well as a substitute to the pressure build-up. It was therefore decided to couple the drawdown test with an interference test so as highlight the subsurface uncertainties. In order to achieve these objectives, careful design and operational coordination between the different asset teams and contractors is crucial to obtain interpretable and useful data.
Water production was observed in some of the nearby wells, and therefore communication between the horizontal well and the surrounding wells needed to be verified. The main objective of this project was to evaluate the reservoir parameters and connectivity surrounding the important horizontal well. In this test, the horizontal well was the active well in a five well interference test. The results of the test indicated different pressure behaviors seen from the observation wells corresponding to the pulse created by the horizontal well. Communication was established in some of the wells, whereas, faults were also verified in the surrounding regions. In addition, the drawdown analysis of the horizontal well showed all the flow regimes that relate to a horizontal wells’ signature as well as boundary behavior which coincide with the interference test results. The results of the drawdown analysis indicate the possibility and accuracy of conducting a pressure transient analysis using this method without being constrained with production objectives, and hence not shutting the well in.
Innovative Noise and High-Precision Temperature Logging Tool for Diagnosing Complex Well Problems
Authors: Ghalem Salim , Draoui Elyes , Mohamed Ayman , Keshta Osama , Serry Amr Mohamed , Al-Felasi Ali , Berrim Ahmed , Abu Chaker Hicham , Filenev Maxim , Gabdrakhmanova Alfiya , Aslanyan Irina , Aslanyan Arthur 
Published: November 2012

Abstract
Abu Dhabi's mature field with more than 50 years of production history and over 350 wells that is presented in this paper is one of the world's largest offshore oil fields. As oil fields mature, water and gas breakthroughs become increasingly frequent and the understanding of fluid movement becomes crucial for proper reservoir management, efficient remedial works and optimum workovers and future wells drilling, which all expected to enhance oil recovery.
This paper introduces an innovative logging technique designed to track fluid movement deep in the formation in flow and no-flow intervals and through casing.
3D OBC Seismic Survey Design Offshore Abu Dhabi - with Focal Beam Approach
Authors: Ishiyama Tomohide , Blacquiere Gerrit 
Published: November 2012

Abstract
We introduce a 3D ocean bottom cable (OBC) seismic survey design flow with the so-called focal beam method for finding the optimum acquisition geometry to satisfy geophysical requirements. This method is based on the so-called common focus point (CFP) technology, and it is a subsurface oriented and target oriented approach, making it possible to quantitatively analyze sought-after attributes, such as potential resolution and pre-stack amplitude fidelity, for one or more gridpoints in the subsurface of a given acquisition geometry.
We implemented the survey design flow offshore Abu Dhabi with several acquisition geometries to understand the effects of essential survey parameters, like 4D spatial sampling intervals with and without symmetric sampling, aspect ratio, roll pattern and wave type to be recorded, on the sought-after attributes. Summarizing these results, the relationship between essential survey parameters and resulting data quality was well understood.
Combination of Properly Engineered Reservoir Drilling Fluid and Filtercake Breaker Improves Performance of Extended Reach Wells Offshore Abu Dhabi
Authors: Saleh Medhat G. , Hassan Mahmoud M. , Medjiah Abdul Kader , Foxenberg William , Conn Tatiana , D'Mello Allwyn 
Published: November 2012

Abstract
This paper describes a combination of reservoir drilling fluid (RDF) and filter-cake breaker technology applied on four extended reach wells offshore Abu Dhabi which and provided multiple improvements in production rates of long horizontal laterals. The need for clean-up acid stimulations was reduced or eliminated in wells that could be beyond the reach of coil tubing.
The paper highlights the field implementation of these fluid systems and details the laboratory developmental work that coincided with the drilling and completion campaign. Three wells have been drilled with specialized reservoir drilling fluids (RDF) that included a premium grade xanthan, modified starch, carbonate with an internal filter cake breaker. Premium lubricants were included in the RDF to ensure that the drilling BHA could reach the ± 20,000 ft target depth and the liners could be run all the way to bottom. Acid stimulation of the nearly 10,000 ft reservoir sections was planned. The first two wells were drilled successfully, liners were run to bottom and the internal breaker was activated by a slightly acidic pH. The acid stimulation has only been performed on them to improve the initial production rate which was already near the expected target rate, while acid stimulation was not required for the third well as its performance has met the expected production rates. Subsequently, the fourth well utilized a more comprehensive cake breaker system and improved lubricant. Results of this well met production expectations also without the need for acid stimulation. Details of each well performance, field operations and results, including the laboratory development program are thoroughly discussed. Furthermore, impact of lubricants on RDF rheological properties, drilling performance and liner running torque and drag is detailed. In addition, the influence of reservoir drilling fluid design, lubricants and delay additives on the performance of the breaker is identified.
An Integrated Approach to Build 3D Fracture Model
Authors: Bellah Samir , Al Hosany Khalid J. , Najia Walid K. , Al Massabi Abdurrahman M. 
Published: November 2012

Abstract
An offshore Abu Dhabi carbonate oil field which was discovered in 1969 and put on production in 1985. The field produces from a reefal limestone formation deposited in the middle cretaceous. The field is characterized by good reservoir properties in the rudest banks well developed in the northern part of the field. Soon after production starts, wells water cut gradually increased to reach 50% within 4-5 years with drastic decline in oil production. Horizontal drilling was implemented with an objective of increasing well exposure to reservoir, reducing drawdown and as such combating water coning/channeling phenomena. Although oil production from horizontal wells was substantially improved, water production trend and production decline, however, did not change in most of the cases.
Reservoir heterogeneities, such as fractures and facies distribution, are believed to be main contributors to a water coning/ channeling phenomena and to the escalation of water production trends. Therefore, understanding of geological, petrophysical, properties of the formation is the corner stone for, controlling water production problems and hence improving reservoir performance. In this contest, the operating company decided in 2006 to acquire 3D seismic to improve the field imaging and embarked in intensive well data gathering program including, FMI, coring, VSP and PLT measurements to improves the knowledge about the reservoir.
This paper will illustrate an integrated approach to build a 3D fracture model of Reservoir-A using a comprehensive full set of geological drivers obtained from seismic attributes, core and logs data which may control and explain the fracture occurrence in the reservoir. The model was used to enhance the history match accuracy and help also to assess new potential ideas for future development.
Low Salinity Enhanced Oil Recovery - Laboratory to Day One Field Implementation - LoSal EOR into the Clair Ridge Project
Authors: Robbana Enis , Buikema Todd , Mair Chris , Williams Dale , Mercer Dave , Webb Kevin , Hewson Aubrey , Reddick Chris 
Published: November 2012

Abstract
Clair Ridge will include the first offshore deployment of BP's reduced salinity LoSal® enhanced oil recovery (EOR) water injection technology. Over the last ten-years, there has been significant growth in the evidence supporting the use of low salinity water injection as a viable EOR process. BP, by using its LoSal EOR technology, has shown that incremental increases in oil recovery can be achieved across length scales associated with core flood experiments (inches), field-based single well chemical tracer tests (feet) and field trials (inter-well distances). This paper discusses the process undertaken by the Clair Ridge project in getting LoSal EOR adopted as a day one, secondary waterflood.
Confirmation and quantification of the LoSal EOR potential at Clair Ridge began in 2006 with completion of a series of core floods using three reservoir rock types. However, it was recognised that as a green field development single well chemical tracer tests or field trials were not possible ahead of sanction. Therefore, confidence in the materiality of recoverable oil by using LoSal EOR was built through integration of core flood data into reservoir simulation studies focused on a thorough investigation of the subsurface, produced water disposal and reverse osmosis operability uncertainties. In parallel, scoping facilities studies were completed to provide cost, weight and footprint estimates for inclusion of a 145 mbd RO plant on the platform. Finally, and critical to the success of this project was early and open partner engagement in LoSal EOR evaluation.
Theoretical Bases of Arps Empirical Decline Curves
Authors: Ling Kegang , He Jun 
Published: November 2012

Abstract
The famous Arps empirical decline curves provide a powerful and practical tool for production forecast. Numerous historical production data proved that Arps decline curves can be applied universally. With that many engineers use Arps decline curve without knowing reservoir properties and operating conditions. The lack in reservoir properties and operating conditions affects the quality of production forecast. Even with the knowledge of reservoir properties and operating conditions a reliable production forecast still cannot be guaranteed if we do not understand the theory that connects reservoir properties and operating conditions to production decline. The demand for a solid theoretical basis for production decline curve analysis trigged this study.
In this investigation, we derived the governing equations of production decline for different reservoirs by combining static geological and reservoir data with dynamic production data. With these equations the Arps decline curves are reproduced for different reservoir fluids and drive mechanisms. These equations indicate that Arps decline curves not only are empirical but also have theoretical bases. Engineers can use our governing equations to forecast production confidently.
Oil Production Optimization for Fields with Sensitive Wells and Gas Handling Limitation
Authors: R Pillai Ganeshram 
Published: November 2012

Abstract

Description
Oil industries with higher potential reservoirs are having restrictions to maximize the oil production when the gas handling capacities are limited with considerations to environment. There can be other limitations such as water handling capacity and well-head sensitivity limitations. To overcome these limitations this paper provides a comprehensive method, which was developed with combination of mathematical tools like curve fitting techniques to build well model from production test results and linear/ nonlinear programming for optimizing the well models.

Application
This method summarized can be applied to optimize/ maximize oil production in matured fields, fields with limitation on gas handling and high GOR limitations. Principle used in this paper can be used in fields with water handling limitation also. This will help reducing impact on environment as well.

Results and Conclusions
Results for maximum oil which can be produced with the gas plant design conditions, limitations are provided in this paper and set of well choke opening for the optimum production are generated by program for different cases. Previous works used the approach to optimize mainly gas lift wells, this paper proposes for oil production optimization, moreover previous works created well performance curves on the basis of oil production or estimations, but this work is based on choke opening and well test results of encoded wells.

Technical Contributions
A novel method of combining well test data to interpolate oil, gas, water production equation (Well performance curves) in terms of well choke opening (which is decision variable) is used. This paper provides optimum oil produced from field, Maximum oil which can be produced from field with different Gas limitations, and field maximum oil production capacity. All the above results are generated without using any specialized software.
Concept-Based Geologic Modeling Using Function Form Representation
Authors: Gai Xiuli , Wu Xiao-Hui , Varban Bogdan , Sementelli Kathryn , Robertson Gregory 
Published: November 2012

Abstract
Industrial standard technologies for detecting subsurface structures and rock properties either have limited resolution (e.g., seismic imaging) or limited coverage (e.g., well logging). It is usually necessary for a geologic model to incorporate interpreted or conceptual geologic descriptions that may have a significant effect on the movement of fluids in the reservoir. The conceptual descriptions or geologic concepts are often uncertain. In practice, it is important to conduct uncertainty analysis of different geologic scenarios, which involves multiple reservoir simulations on different geologic models with varying conceptual descriptions. Furthermore, when production history is available, it is important to adjust geologic models such that predictions based on these models match the production history. In either case, many reservoir simulations are usually required. Thus, precise and efficient modeling of geologic concepts while honoring measured data is critical to the successful application of geologic modeling.
In this paper, we present a function-form geologic modeling technique that allows for rapid construction and updating of geologic models with descriptive geologic concepts. Pre-built and re-usable concept models are used, which include elements and properties that may affect the flow response in the reservoir model. A concept model encapsulates rules and parameters that control the creation of geologic models based on a geologic concept. Explicit and implicit functional representations of geometry and 2D/3D property distribution are used to define concept models. Functions are parameterized and can be adjusted to honor measured data and to generate different realizations of concept models. Examples of using the function-form modeling technique will be presented for deep-water channelized systems.
Concentric Coil Tubing Helps Solve Challenging Acid Flow Back in High H2S Content Well
Authors: Ababou M. , Al Mujaini R. , Quesada C. Velazco , Taha W. Afify 
Published: November 2012

Abstract
Recovering acid after a stimulation job can prove to be very challenging in sandstone reservoirs, especially if the well has a potential to produce H2S. When the customer's gathering station is unequipped to handle acid or water, then it becomes impossible to flow the acid via the flow lines. The acid must be disposed at the surface in a separate facility as fast as possible. Allowing the acid to remain downhole for long time carries the risk of damaging the sandstone reservoir due to secondary precipitations. The customer, as per standard operating policy, does not allow flowing back fluids into their pits. Only return tanks are allowed, adding to the difficulty of flowing back stimulation fluids.
With the help of concentric coiled tubing, an innovative technique to produce back acid from H2S wells became the sole solution to a major flowback challenge in South Oman wells. The technology successfully enabled the recovery of stimulation acid from a customer's well that had high H2S content, without producing any H2S at surface. The unique approach consisted of mixing an H2S scavenger with a scale inhibitor. This mixture was used as the power fluid for the concentric coiled tubing tool. With the help of the good shearing energy at the WellVac BHA, combined with the small concentric coiled tubing return annulus, the H2S scavenger solution was perfectly mixed downhole with the return fluids, and no H2S was produced or recorded at the surface return tanks. This new technique will certainly open new possibilities to stimulate many more wells that could not be stimulated previously due to high H2S content. The technique would also eliminate the great costs of a portable flare system.
Ion Chromatography Analysis of Advanced Ion Management Carbonate Coreflood Experiments
Authors: Vo Loan T. , Gupta Robin , Hehmeyer Owen J. 
Published: November 2012

Abstract
Advanced Ion Management (AIM) is an enhanced oil recovery (EOR) process where waterflood injection water is modified by the addition, removal, or dilution of ions. AIM can yield an increase in oil recovery compared to waterflooding using formation brines. To better understand the oil recovery mechanism of AIM in carbonates, ion chromatography studies and salt solubility measurements were conducted on AIM brines used in floods of Middle Eastern core.
The ion composition of the brines – upon mixing after extended time, at reservoir temperature and pressure, and after core flooding - were compared to elucidate the ion composition changes during an AIM waterflood and how those changes could lead to additional oil recovery. That knowledge could potentially be used to screen reservoir rock types and available water sources to determine which would be best suited for EOR from AIM waterflooding.
AIM technology encompasses a wide range of injection brines, and thus this ion chromatography analysis covers a range of modified brines, including brines for which analyses have not been previously published. Analysis of the results has implications for how ion composition may be correlated with oil recovery and what facilities are required to obtain the desired composition. The study finds that neither rock dissolution nor ion exchange alone is sufficient to explain oil recovery with modified brine injection, and neither mechanism is a guarantee of additional oil recovery. It also finds that sodium phosphate, borax, and sodium sulfate all precipitate divalent cations from seawater at field operating conditions.
Experimental and Theoretical Investigation of Water/Gas Relative Permeability Hysteresis: Applicable to Water Alternating Gas (WAG) Injection and Gas Storage Processes
Authors: Fatemi S. Mobeen , Sohrabi Mehran 
Published: November 2012

Abstract
Accurate determination of relative permeability hysteresis is needed for reliable prediction of WAG injection. We report two series of gas/water kr hysteresis curves obtained from corefloods under mixed-wet conditions. The first set began by water injection (imbibition: I) in the core saturated with hydrocarbon gas and immobile water. Then, the injection of gas (Drainage: D) and water continued sequentially and in total, three imbibitions and two drainages were carried out (IDIDI). In the second series, the core was initially 100% saturated with water and the experiment started with drainage (gas injection) followed by successive imbibitions (water) and drainages (DIDIDI) periods. The measured pressure drop and production data were history matched to obtain krg and krw values for each imbibition and drainage. The results show cycle-dependent hysteresis for both krg and krw curves. Therefore, the current assumption in existing hysteresis models that the drainage scanning curves follow the preceding imbibition curve is not supported by our experiments. Historic behaviour of both krg and krw is qualitatively different for these two series of experiments. This shows that unlike water-wet systems, relative permeability historic behaviour in mixed-wet system can be a function of injection scenario (saturation history). In the IDIDI series, both krg and krw decreased as the alternation between imbibition and drainage injection continued. In the DIDID series, no significant hysteresis was observed for krw, but krg in drainage cycles were higher than the corresponding values in preceding imbibition cycles. The results reveal that, none of the widely used hysteresis models (e.g., Carlson, Killough) is able to predict the observed cyclic kr hysteresis for alternating injection of gas and water. The results suggest that for mixed-wet systems it is necessary to consider irreversible hysteresis loops for both the wetting and nonwetting phases. In addition to WAG injection, the results presented in this paper and the conclusions drawn also have applications in underground hydrocarbon gas storage which usually involves cyclic pressurization (drainage) and depressurization (imbibition) on annual basis.
Design & Implementation of CO2 Huff-n-Puff Operation in a Vietnam Offshore Field
Authors: The Ha Giang , Dinh Tran Ngoc , Vu Huy Huu , Takagi Sunao , Mitsuishi Hiroshi , Hatakeyama Atsushi , Uchiyama Tadao , Ueda Yoshiaki , Van Nguyen Toan , Phan Trung Ngoc , Nguyen Hoan Ngoc , Nguyen Trung Huu , Dinh Quan Manh 
Published: November 2012

Abstract
The Carbon Dioxide Enhanced Oil Recovery (CO2 EOR) application to the offshore oil field in Vietnam has been investigated through an international joint study scheme between Japan and Vietnam since 2007 and a preliminary study for potential CO2 EOR application indicated feasibility to some extent. To reduce and mitigate technical uncertainties/risks in the field scale EOR implementation, in May 2011, a CO2 EOR pilot test was executed in a sandstone reservoir of Rang Dong oil field, offshore Vietnam.
The test was designed to be conducted as a single-well test, and generally called CO2 Huff-n-Puff. Major field operations included test string installation, pre-CO2 injection flow, CO2 injection (ca. 111 metric tonnes) and post-CO2 injection flow. Whole operation was performed satisfactorily with all objectives achieved. During the test, clear increment of oil rate and reduction of water cut were observed after CO2 injection as well as oil composition change. The contrast of CO2 injectivity and oil saturation change in the reservoir was confirmed by saturation logs, etc.
Being the first CO2 EOR application in Southeast Asia and also offshore application worldwide is rarely reported, the operational gained is especially valuable. This paper is to describe the process of engineering design, planning, onshore preparation and field execution leading to the success of the project1.