bluuebunny/crossref_metadata_2025_split huggingface dataset:
First Successful Low Cost Abrasive Perforation with Wireless Assisted Coiled Tubing in Deviated High-Pressure/High Temperature Gas Well
Authors: Núñez-Garcia Walter , Solares J. Ricardo , Leal Jairo , Duarte Jorge , Chacón Alejandro , Heidorn Robert , Izquierdo Guillermo 
Published: February 2011

Abstract
A number of highly deviated gas producing wells in the southern area of the Ghawar field of Saudi Arabia were recently perforated using coiled tubing (CT) conveyed guns. However, after performing several jobs, it was found that the cost of using the tubing conveyed perforating (CT-TCP) approach was significantly higher than anticipated. Therefore, it became apparent that more cost effective options were required. The decision was then made to trial test the CT abrasive hydrajetting perforating technique.
A well with a gross pay thickness of 130 ft was then selected for the first trial, considering that the chance of achieving job objectives is higher if the selected interval to perforate and the number of slots that can be made in the formation in one run are not excessive. Thus, it was decided to create slots in 12 different sections along the wellbore. Given this constraint, it was important to achieve an optimum depth correlation, which was done by using a wireless real-time CCL tool for the first time in this type of operation in Saudi Arabia. A procedure designed to optimize implementation time and chemical volumes was prepared, and the job was successfully performed with better than expected results.
The objective of this paper is to share results, lessons learned, and solutions used to overcome problems and achieve the successful implementation of a technique offering a valid, low-cost alternative to conventional perforating in a highly deviated well. Full details of the planning and design of the job, operational procedures and data collected are also provided.
Impact of Oil Viscosity Gradient Presence on SAGD
Authors: Chen J. X. , Ito Y. 
Published: February 2011

Abstract
The presence of an oil viscosity gradient appears to be a real phenomenon in the field and its influence on the SAGD process has been studied by various researchers. However, there is potential to refine previous results to exploit the impact of viscosity gradients on SAGD oil recovery process performance. This paper covers our simulation study of the impact of an oil viscosity gradient presence on SAGD operation. Various SAGD operating scenarios in the reservoir with the presence of a vertical oil viscosity gradient were investigated and simulated. The conclusions are summarized as follows:
The presence of a vertical oil viscosity gradient in the reservoir had a mild effect on the SAGD oil recovery rate, while the effect on the oil recovery factor was insignificant. J-Well SAGD, in which a J-well replaces the horizontal producer in a standard SAGD well configuration, did not perform as well as SAGD with a standard well configuration (two parallel horizontal wells). These two conclusions are not in agreement with previous findings by other research groups. Observations from some SAGD field tests indicate the steam chamber could fail to reach the top of reservoirs. For those cases, gas injection could potentially help to recover the oil from the layer above the steam chamber. If that is true, the presence of an oil viscosity gradient might have some impact on SAGD performance with gas injection.
Since local steam trap control is required for J-Well SAGD operation in order to optimize performance, the challenge and feasibility of local steam trap control are also discussed in this paper. Some of the SAGD field evidence will be provided to support our simulation results.
Well Integrity and Workover Candidates for Existing Wells in the Wabamun Area CO2 Sequestration Project (WASP)
Authors: Nygaard R. , Lavoie R. 
Published: February 2011

Abstract
Geological storage of CO2 requires that policy makers, regulatory agencies, and industry ensure that these operations are safe for the public and that sequestered CO2 is permanently removed from the atmosphere. One possible risk identified with storing CO2 into the subsurface is the potential for leakage through existing wells penetrating the cap rock. This study evaluated the well integrity for existing wells in the Wabamun Area as part of a University of Calgary lead study which examined the feasibility of storing 20 Mt-CO2/year for 50 years within 60 km of Wabamun (WASP- Wabamun area CO2 Sequestration Project). A number of large stationary CO2 emitters are located in central Alberta with cumulative annual emissions in the order of 30 Mt CO2. A discrete approach was taken where each individual well was investigated and the need for any additional workovers were on the basis of a decision matrix developed based on current knowledge of well integrity for CO2 injection schemes. When analyzing the existing well population only 4 out of 27 wells were identified as work over candidates. This result demonstrates that well leakage from existing wells is less of a mitigation problem than was first anticipated for this area. For the existing wells only a few had production casing installed through the Nisku formation, which is a situation more prone towards leakage. The other wells had cement plugs through the cap rock with a cement type that will prevent leakage through the Calmar shale. For existing wells that do require work overs, it is recommended they be performed prior to pressurizing the reservoir area. The cost and complexity of properly abandoning these wells will be higher at higher pressures or when CO2 and possibly H2S are present.
Reserves Management: A Concerted Effort
Authors: McMahan Nathan , Munoz Efren 
Published: February 2011

Abstract
Traditionally reserves management has been an exclusive function for Reservoir Engineers; however in mature fields the need to involve Production, Facilities, Geology, Operations Engineers and Financial Analysts is critical. This paper presents a suggested workflow to improve the way reserves are evaluated, supported, booked and documented with a concerted effort of a multidiscipline team. This paper is focused on tight gas reservoirs and the central idea is to reduce the uncertainty that is always present when dealing with reserves.
Most of the discussion is concentrated in understanding and verifying the hyperbolic decline "b" factor to be used for production decline analysis; we normally understand the mathematical meaning, but very rarely spend the time understanding the physical meaning and the consequences of using the wrong value. Once the "b" factor is defined, the proper documentation must be filed for each reserve record and the focus becomes the economic analysis of those reserves which is critical for future development especially in a very volatile economy in which prices are fluctuating a lot.
Interpretation of Immiscible WAG Repeat Pressure Fall-Off Tests
Authors: Stenger Bruno A. , Al Kendi Salem A. , Al Ameri Ammar F. , Al Katheeri Abdulla B. 
Published: February 2011

Abstract
This paper reviewed the interpretation of repeat fall-off tests acquired in two vertical pattern injectors operating in a carbonate reservoir undergoing full field development. Water Alternating Gas first pattern (WAG-1) started in August 2002 with a period of continuous gas injection until 2006 when the first water cycle was initiated. In the second pattern (WAG-2) water injection was initiated in June 1998 until September 2007 when the first gas cycle started.
A few pressure fall-off tests were acquired during the monophasic injection phase mostly to verify well injectivity. After Water Alternating Gas (WAG) cycles started, pressure fall-off tests were usually acquired at the end of each three-month injection cycle with 1:1 WAG ratio. Analytical fall-off test interpretation relied on the use of the two-zone radial composite model. The apparent permeability thickness product was corrected with the Perrine formulation of multiphase mobility. Triphasic oil permeability was calculated using the modified Stone I model. Multiple fall-off test interpretations indicated that the two pattern vertical injectors behaved differently even though both being fractured. The difference in behavior was linked to different perforated intervals and reservoir properties. Gas and water injection rates were showing differences between both pattern injectors as a consequence. No major operational issue was reported during the three-year operation of both WAG patterns. During the WAG cycles, gas banks were found to be of a small inner radius and almost undetectable at the end of the subsequent water cycle. Changes in the pressure derivative slope at the end of the subsequent water injection cycle indicated most likely the creation of an effective mixing zone of injected gas and water in the reservoir.
Numerical finite-volume simulation was required to account for potential injected fluid segregation and, the multi-layered and heterogeneous nature of the reservoir. Repeat saturation logs acquired in observation wells provided critical information on the saturation distribution away from the injection wells. Enhanced vertical sweep conformance through phase mobility control in the presence of strong reservoir heterogeneity was the major expected benefit from an immiscible WAG displacement mechanism. All available observations were reviewed and integrated using a history-matched reservoir simulation sector model with boundary conditions obtained from a full-field model.
Challenges for Horizontal Well Placement Optimization in a Giant Mature Onshore Oilfield, Abu Dhabi, U.A.E.
Authors: Clark Andrew , Al Suwaidi Mohammad , Elabed Amjad , Mead Jeremy 
Published: February 2011

Abstract
The well planning process in ADCO (Abu Dhabi Company for Onshore Oil Operations) is usually driven by subsurface disciplines as part of a full field development plan and consists of a limited number of development iterations related to surface (natural or man-made obstacle) or subsurface (anti-collision, dog leg severity) constraints. The apparent simplicity of this development description is hiding a much more complicated reality for many of the Abu Dhabi giant oilfields that have been producing for several decades. ADCO manages one such asset and is now developing previously untapped reservoirs within an existing mature field and is facing issues such as positioning new facilities; the necessary replacement and upgrade of old surface facilities; surface and subsurface congestion; continuous appraisal activities of additional hydrocarbon-bearing reservoirs; increased HSE compliance and competing land utilization requirements from third parties. Added to this is the diversity and complexity of the professional Information Technology software currently used by the surface and subsurface disciplines, most of which are legacy systems that are not integrated. As such, the business problem of planning and drilling several hundreds of new horizontal wells becomes more critical over time.
Several initiatives have been launched at Company level in order to address these issues such as streamlining the well placement process by using a new workflow Well Approval Process; a common corporate Geographic Information System (GIS) interface, as well as the planned integration with a Drilling Real Time Operations and Control centre (RTOC) for drilling follow-up activities.
While the current process always led to well placement in line with state-of-the-art practices, the on-going process improvements are expected to decrease the current stress level on surface and subsurface asset teams and ensure a manageable load level as drilling activity is scheduled to increase three-fold in the coming two years. This paper discusses the history of the field, its geological setting, the development of surface and subsurface assets and the challenges now being faced and how the challenges are being over come to ensure continue its continued development.
Well Integrity in Heavy Oil Wells: Challenges and Solutions
Authors: Taoutaou S. , Osman T. M. , Mjthab M. , Succar N. 
Published: February 2011

Abstract
Unconventional resources such as Heavy oil are becoming a target of most operators. Wells subjected to steam stimulation for heavy oil recovery are exposed to extreme temperature changes that can vary from 21° C to 348°C. This temperature cycling can have a drastic effect on the set cement sheath causing it to fail with a consequent loss of the well integrity. Loss of hydraulic isolation in the cement sheath will decrease control of steam placement leading to reduced hydrocarbon recovery and potentially health, safety and environmental challenges.
Oudeh Petroleum Company (OPC) has been producing heavy oil since 2006 using the Huff and Puff technique. Complete Well Integrity has been achieved using an Advanced Cement System in more than two hundred wells exposed to steam injection temperatures up to 348°C and consequent high induced thermal stresses (Fig. 1 & 2).
This paper will discuss the methodology of the risk analysis of the cement sheath failure under steam stimulation and selection criteria for the Advanced Cement System to withstand temperature cycling. Two case histories will be presented as well as a 50 well database.
Demonstration of the Power of Inter-Disciplinary Integration to Beat Field Development Challenges in a Complex Brown Field-South Oman
Authors: Belushi F. , Busaidi R. , Mahruqi S. , Lukmanov R. , Mehdi R. 
Published: February 2011

Abstract
An integrated understanding of static and dynamic issues is essential to generate an appropriate life cycle FDP. This abstract will highlight the power of such integration.
First pass dynamic modeling gave very poor history match results. The model significantly under produced the historical gross volumes. Sensitivity analysis on the permeability multiplier, Kv/Kh, viscosity and relative permeability curves were utilized to improve the history match, however, the improvement was limited.
Careful investigation showed that the main reason for the poor history match was the underestimation of permeability in apparently low porosity intervals. These previously unrecognized flow units also contributed to a high vertical heterogeneity.
Further integration and analysis of various petrophysical data, combined with reservoir performance behavior, suggested that these additional flow units were conglomeratic intervals of different gravel sizes. These intervals are characterized by reduced bulk porosity because of the presence of low porosity pebbles in the otherwise highly permeable sandy matrix. Following this re-interpretation, a new realization of the conceptual depositional model, that incorporates the new litho-facies, was constructed.
The static inputs were re-visited; however, due to the lack of core data, identification of the permeability range of the new litho-facies was complicated. This forced maximum utilization of the basic static/dynamic data and analogues.
Analysis of borehole rugosity, oil saturation, reservoir performance and pressure data strengthened the adopted subsurface concept model. A recent core, taken from this reservoir, revealed the presence of conglomerates comprising hard clasts cemented by unconsolidated sands and thereby finally confirmed the interpretation.
The updated models, with minor fine-tuning in dynamic parameters, showed a step change in the history match. This outcome confirmed the presence of high permeable facies despite the low porosity reading at these intervals.
It can be concluded that the vertical heterogeneity, which is often overlooked, can cause complex issues in history match process. However, the better understanding of these features, through multidisciplinary approach, is the key to drive the right solution.
Moreover, maximum utilization of the basic data can paint a picture beyond its anticipated frame. Despite the lack of core data, compiling the subsurface data through multidisciplinary integration provides a powerful tool to mitigate subsurface uncertainties.
First Surface Driven PCP Application on Alaska’s North Slope
Authors: Young James P. , Mathews William L. 
Published: February 2011

Abstract
Alaska’s North Slope (ANS) contains a large resource of heavy oil above two of the largest producing fields in North America, but due to the complexity of producing heavy oil in an arctic environment, remains untapped. Development of heavy oil in the Arctic represents a significant departure from conventional oil developments on the North Slope as well as established heavy oil developments elsewhere in the world. This paper describes a cold heavy oil production with sand (CHOPS) test using a surface driven progressive cavity pump (PCP) to evaluate the resource for commercialization. Despite success using this technique in other heavy oil applications, significant design challenges remain. The test recovered significant quantities of oil and sand at minimal drawdown; however, the capacity of the well was limited by surface torque values that were significantly higher then anticipated and ultimately resulted in a rod failure after 3-weeks of production. Further analysis indicated that torque was dominated by drag forces between the continouous rod string and the oil. Followup testing using oil produced from the well was completed with specially designed test equipment to identify the source of the unexpectedly high torque and provided data to improve rod torque prediction. As a result of the work performed, the remaining three wells in the initial pilot were designed with significant upside in capacity.
Due to restrictive surface locations and permafrost, effective solids transport in deviated wellbores and its effect on equipment wear are key considerations that need to be better understood.
On SAGD in Oil Sands Reservoirs With No Cap Rock
Authors: Alturki A. , Gates I. D. , Maini B. 
Published: February 2011

Abstract
The ever increasing world demand for energy to satisfy the current needs and future economic growth has forced the oil and gas industry to exploit challenging energy resources. Heavy oil and oil sands are challenging due to the complexity of the reservoirs together with the high oil viscosities which are often greater than hundreds of thousands to millions of centipoise. Most steam-based recovery processes such as Cyclic Steam Stimulation (CSS) and Steam-Assisted Gravity Drainage (SAGD) require a competent cap-rock to prevent excessive steam losses and maintain good thermal efficiency and production rates. However, there exist significant amounts of oil sand resources which have little or no cap-rock and thus, at this point, these resources are considered inaccessible. This research examines the feasibility of using SAGD in oil sands reservoirs with no cap rock with detailed thermal reservoir simulation. The results of this research provide guidelines on how to implement the SAGD process in shallow oil sands reservoirs with no cap rock. This could unlock a resource that is currently considered inaccessible. The results show that vertical chamber growth can be controlled to some extent by using variable pressure operating strategies and co-injection of a non-condensable gas such as methane. In oil sands reservoirs without cap-rocks, pressure control is critical especially if there is to be minimal fluid invasion from the oil sands formation into the water zone above. However, the pressure must be sufficient to delay or prevent flow of water into the steam chamber. This study is important since in Alberta, Canada alone there are billions of barrels of shallow oil sands resources without sufficient cap rock to operate conventional high pressure steam recovery processes such as CSS and SAGD. The results of the study provide a technical basis to design feasible low pressure steam processes for such reservoirs.
A Numerical Study on the Deformation of Even Thickness PCP's Stator
Authors: Zhang Jin , Li Wei , Zhang Shicheng , Wu Tingwen , Zhang Yuguang , Zhou Wanfu , Bai Baojun 
Published: February 2011

Abstract
This study focuses on analyzing the deformation characteristics of the elastomer in an even thickness PCP under several simulated working conditions. A three dimensional finite element model involving one pitch length of stator is established to simulate the deformation of the elastomer. It is known that a proper magnitude of interference of the contact pair between rotor and stator is necessary to ensure a proper contact status. An oversize of interference will induce too severe strain as well as too much resistance of torque moment. Nevertheless a deficient interference can not meet the requirement to form the suitable sealed line. Normally an elaborate uniform interference over all contact pair is designed to expect a satisfied contact interaction. However, not only the magnitude of interference is changed because of several factors, such as cavity pressure, thickness of sleeve, dissolution expansion of elastomer, deformation due to temperature change, etc., but also the interference may become unbalanced over the whole contact pair.
In this paper cavity pressure coupled with Poisson’s ratio of elastomer is firstly considered to investigate the deformation rule of elastomer sleeve. After that a rotor rotating in a stator is simulated to predict the characteristic of torque moment and the stress and strain of elastomer sleeve.
Inherent Dangers in PCP Run-Life Field Data Analysis
Authors: Sheldon John , Skoczylas Paul , Alhanati Francisco 
Published: February 2011

Abstract
When performing statistical analyses on PCP run-life data, one can easily reach incorrect conclusions if subtle but important issues are not fully understood. This paper illustrates some of these issues using examples from analysis work conducted recently with a relatively large and complete set of data collected from several large operators. Issues examined include misinterpretation of single-variable correlation results and run-life measures. It is impractical to design and conduct lab or field experiments to investigate the effect of individual variables on PCP run-life. On the other hand, with normal field data, it can be difficult to isolate the effects of individual variables. The assumption of “all else being equal” rarely applies to field data. Additionally, different run-life measures can give different results at different times in the life of a field, even when the underlying system reliability has not changed. Awareness of these issues is essential to all companies that collect and analyze PCP failure and run-life information for the purpose of evaluating and improving PCP system performance.