bluuebunny/crossref_metadata_2025_split huggingface dataset:
Plug Indicator System Prevents Calculated Volume Errors in Subsea Casing for Primary Cementing Operations
Authors: Caldwell Rebecca , Scott Thad 
Published: February 2011

Abstract
Typically, the position of the top cementing plug in a subsea casing string cementing job is approximated based on the calculated casing volume, however, for various reasons, this volume often varies significantly from actual string volume, especially in long, heavy subsea casing intervals. These discrepancies can create significant challenges during primary cementing operations: If the top plug is higher in the string than anticipated the cement displacement ceases prematurely, preventing the top plug from bumping. This technique prevents over-displacement of cement, but leaves excess cement in the shoe track and increases drillout time.Conversely, the top plug may be lower in the string than anticipated, resulting in the plug bumping unexpectedly at a high displacement rate. This can lead to plug bypass, subsequent over-displacement and a mixture of cement and mud in the shoe track.
Operators using dual cementing plugs have attempted to avoid displacement errors by recognizing the volume required to bump the bottom plug. This method has proved to be unreliable because of the freefall effect of cement in the casing string and, in most cases, rupture of the bottom plug can neither be observed nor recorded.
A new plug indicator system (PIS) has been developed which addresses these problems by providing a positive indication on the rig floor of the top plug’s exact position in the casing string shortly before the plug will bump. This indication is produced by a specialized sub installed in the casing string above the plug’s landing surface. As the top plug passes through the sub, a brief increase in displacement pressure is recorded at surface. This enables the operator to confirm the plug’s exact position in the string, mitigating the risk of cement over-displacement and enabling controlled bumping of the plug, optimum cement placement and minimum drillout time.
This paper addresses the problems associated with accurately locating a top cementing plug and describes the principles of operation of the PIS and its deployment in subsea casing-string cementing. This paper will provide details of the experience gained from the use of the PIS in the field, with a detailed case study of a deep, subsea Gulf of Mexico well.
Development and Application of an Improved Workflow for Developed Reserve Forecasting
Authors: Lyford P. A. , Cibich W. , Chipperfield S. T. , Helfrick G. 
Published: February 2011

Abstract
Across the Cooper Basin (on-shore South Australia) historical trends of developed reserves have shown annual growth. This highlights the understated potential in the area and the under-lying difficulty in quantifying the true value of a tight gas well early in its life. This difficulty generally arises from the challenge of forecasting multi- layered reservoirs with variable surface conditions using traditional decline curve analysis. This conservatism impacts significantly on a company's value through underestimation of developed reserves thus magnifying the negative impact on the accounting depletion rate and profitability of an asset.
This paper details a process of organisation change designed to stabilise this ‘reserve growth’ by defining an "unchanging" best estimate of developed Estimated Ultimate Recovery (EUR). This process involved an improved technical workflow which utilises advanced Production Data Analysis (PDA) rolled out and applied across a large technical department.
This revised process was successfully implemented within three months in a resource constrained department involving an intensive training phase and an external audit. The process resulted in improved technical understanding of the department in advanced PDA, well models on over 70 wells and, most importantly, a gain of over 115 Bcf of 2P developed reserves.
In addition to these immediate reserve estimations and asset profitability improvements, the development of these analytical well models has allowed the asset teams to develop a greater understanding of field and well performance, has overcome surveillance gaps and allowed teams to discover further opportunities.
This technique is not a perfect solution but a significant step forward. With the process now standard within the department it is expected that decline forecasts will continually improve for these complex reservoir systems, which in turn will more closely reflect the value ascribed to these assets.
CO2 Storage Capacity – Combining Geology, Engineering and Economics
Authors: Allinson W. G. , Cinar Y. , Neal P. R. , Kaldi J. , Paterson L. 
Published: February 2011

Abstract
This paper argues that any capacity estimation method requires a combination of geological, engineering and economic analysis in order to provide rigorous capacity estimates. It also argues that the classification of capacity estimates should follow concepts in the existing SPE Petroleum Resource Management System as closely as possible. The Energy & Environmental Research Centre (EERC) (Gorecki et al., 2009) have developed a definition of "practical storage capacity" that parallels the definition of petroleum reserves as "the quantity of hydrocarbons which are anticipated to be commercially recovered from known accumulation at a given date forward", but the EERC acknowledge that there is currently a problem with implementing a price of carbon. This paper develops the economic analysis further than the EERC. Like the EERC, we demonstrate that analytical and numerical injectivity modelling based on geological models of the subsurface can help determine practical storage capacity.
In doing this, the paper makes observations about methods for estimating storage capacity, shows results of reservoir simulations and economic analyses, draws on SPE and internationally accepted methodologies and definitions of petroleum resources and discusses how equivalent definitions can be applied to storage capacity. Finally, the paper provides recommendations for an improved CO2 storage capacity classification system.
Study on Remaining Oil Distribution after Polymer Injection
Authors: Cheng Jiecheng , wei Jianguang , Song Kaoping , Peihui Han 
Published: February 2011

Abstract
The recovery efficiency by polymer flooding is 10% higher than that of water flooding for main reservoirs in Daqing Oil Field, and yearly oil production rate by polymer injection has continuously reached over 10 million tons for 8 years. However, to further enhance oil recovery, it is very important to know how many oil remained in the reservoirs after polymer injection as well as its distribution. The paper took use of logging data of 200 new drilling wells to make macro analysis on remaining oil distribution after polymer injection, and based on the data of coring wells, collected from the same well group in Western Fault of B1 Region, before and after polymer flooding, respectively, core membrane fluorescence technology was used to conduct the analysis on microscopic remaining oil distribution.
The macro analysis results indicate that swept thickness of the reservoir increased 21.4% from 68.6% of water flooding to 90% of polymer flooding, and oil saturation reduced 11.9% from 52.8% to 40.9%, and displacement efficiency has went up 7.6 percentages. The residual oil distribution after polymer flooding is scattered in horizontal direction, while it is interleaved in vertical direction. Following polymer flooding, 10.6% unswept thickness is mainly distributed in thick oil layers, and most of remaining oil within thick oil layers lies in the interlayers and at the top of thick oil layers, which its effective thickness is close to 80%. From the macro point, remaining oil is mainly located in distributary line or some places where injection and production relation is imperfect or the phase is changed, and oil saturation located in distributary line is 4.4 percentages higher than that along mainstream line. The micro analysis results show that the behavior of remain oil distribution is similar to water flooding, which is mainly controlled by capillary force.
Study and Application of Profile Modification in Offshore Fields
Authors: Liu Ming , Wang Yunxian , Liao Xinwu , Zhao Chunming , Yang Qinghong , Yan Ruichang 
Published: February 2011

Abstract
This paper presents the findings from the study and application of profile modification in offshore fields and discusses how to select the proper agents and manage the operation for reservoirs with different geological characteristics.
China inner sea-Bohai is one of the most important oil-producing areas in China. The reservoirs are complex with a great variety in geology and properties of rock and oil. Most of them are medium to high permeability heavy oil reservoirs. Because of high viscosity ratio of oil to water and strong heterogeneity of formations, injected water break through quickly along one direction/layer after waterflooding starts. In order to enhance the water sweep efficiency and improve the oil recovery, the study of profile modification from injectors has been conducted since the year of 2003. Through the study and practice for several years, the technology of profile modification for different types of reservoirs has been developed.
There are six main factors affecting the performance of profile modification in offshore fields. First is the available space on platform for the installation of the operational equipment. Second is the type of profile modification agents. Third is the property of formation liquids, specially the salinities of formation and injected water. Fourth is the procedure of applying the technology. For medium to low permeability formations, the concentration of slugs injected should be in the order of: low-medium-high; for high permeability multiple zones, the order should be: high-medium-low. Fifth is the injection rate of the agent (especially for polymer). Sixth is the amount of agent injected.
The application of this technology has improved the performance of waterflooding and played an important role in sustaining oil production in Bohai. Up to date, 53 times of all kinds of profile modifications have been applied and the incremental oil is about 4 MMBO.
Understanding Value of Appraisal Information through Geologically-Constrained Engineering Scenario Analysis in Economic Modeling of CO2 Storage Site
Authors: Marmin Norhafiz 
Published: February 2011

Abstract
Carbon dioxide (CO2) geological storage is considered in many large "greenfield" developments. The requirements for long-term injection operations have put a premium on obtaining the right information early, constraining engineering solutions and costs before major investment decisions are reached. Information such as long-term field pressure evolution and local fracture gradient alteration may have major impacts on development cost forecast. Reservoir heterogeneity and compartmentalization may result in continuous reservoir pressure escalation as injected CO2 amount increases. Maintaining rate is essential to avoid venting. However, this requires proportionate injection pressure increases—an option bounded by formation integrity, seal capacity, and well interference limits. When operating conditions approach these limits, one may avoid compromising rate by, albeit costly, drilling more injection wells over time. We investigate the impact of mean reservoir parameter and boundary condition assumptions on project economics. The potential impact of injection temperature on formation integrity and in-field power needs is also explored. Well injection rate is estimated analytically using a Darcy law's approximation. Taking high seal entry pressures as a given, the study defines allowable injection pressure in terms of fracture gradient. Upward fracture gradient adjustment is modeled for escalating reservoir pressure, allowing mitigation of injection rate reduction. We later analyze the variation of fracture gradient with injection temperature to account for thermal fracture limitation. Ultimately, the study presents pre-tax break-even CO2 unit technical costs in dollar per tonne injected, providing comparison of relative economic performance among the investigated scenarios. The results demonstrate the importance of reservoir quality in suppressing cost-intensive injection well and CO2 heating requirements. The range of costs indicates the value of early appraisal information before making development decisions. The application of geologically-constrained engineering analysis in economic modeling is useful in providing insight on value of information as well as supporting decisions for CO2 storage site development.
Squeezing Blood From a Stone — Distinguishing Incremental From Accelerated Recovery in Moderate to Tight Gas Infill Development Using Production Data Only
Authors: Wong J. R. , Shrivastava R. , Headland M. K. , Chipperfield S. T. , Blasingame T. A. 
Published: February 2011

Abstract
With increasing demand for natural gas, higher product prices and the availability of improved extraction technologies, there is increasing focus on infill drilling in tight gas reservoirs. However, quantification of incremental recovery (one of the key value generators) is often challenging particularly in commingled multi-layered heterogeneous fluvial reservoirs with a paucity of data collection. The issues related to the volume and quality of data collected are magnified when low cost infill development is undertaken. This paper demonstrates a new technique using production data (in isolation) to estimate incremental and accelerated recovery for such a development.
For infill development, various methods have been proposed to quantify incremental recovery. The most common range from simple reservoir continuity models, Arps Decline Curves, Material Balance, field analogue studies, to complex reservoir simulation. This paper discusses a new methodology termed ‘Progressive Multi-well Blasingame Analysis’ based on Blasingame type curves which successively compares boundary-dominated responses from each infill phase to distinguish incremental from accelerated recovery achieved from each phase of infill development.
The paper reviews the theoretical support for the Progressive Multi-well Blasingame Analysis method via a numerical simulation study. Demonstration of this methodology is performed using a field case study to quantify incremental recovery and identify additional infill opportunities in an environment where limited reservoir surveillance was conducted. The paper concludes by discussing the applicability and the pros and cons of this technique.
In essence, this paper addresses an existing knowledge gap in industry as it provides a method to efficiently evaluate a group of wells and distinguish incremental from accelerated recovery using only the production rate and flowing tubing head pressure data.
Proper Analysis and Integration Of Production Data From Cbm Reservoirs Improve Future Prediction
Authors: Shwe (George) Hla , Baker Sarah 
Published: February 2011

Abstract
Unique properties and behaviour of coal seams reservoirs make prediction of future production a challenge for production and reservoir engineers. Fluid flow in coal seams is governed by coal properties as well as the method of completion and production. It is difficult to conduct the task without a thorough analysis of production data.
Analysing the production performance in coal seam beds can be a daunting task, particularly at the early stage of production life of the field. A great deal of time and effort are spent in filtering and analysing a large amount of production data, which is used to determine key properties (e.g. permeability, average reservoir pressure, bottom hole flowing pressure). Arguably, prediction of coal seam reservoir performance is entirely dependent upon the input reservoir data used in the simulation model.
It is almost impossible to acquire data such as pressure on daily basis. The method in the paper used all available data (e.g., gas rate, water rate, casing pressure, tubing pressures and fluid level) to calculate bottom hole flowing and average reservoir pressure that is later calibrated with measured pressure from dedicated monitor wells. These data can then be history-matched in analytical and numerical models.
The paper will be presented with specific well history- matching to illustrate the method used in the study and relativity to the results generated from simulation model. The analysis will focus on specific well cases and illustrate scenarios that are applicable in other coal seam reservoirs.
Drilling and Completion Challenges and Remedies of CO2 Injected Wells with Emphasis to Mitigate Well Integrity Issues
Authors: Hossain M. M. , Amro M. M. 
Published: February 2011

Abstract
CO2 emission is generally accepted to be one of the prime causes of global warming and climate change issues. In order to combat this global warming by reducing CO2 emissions, there are numerous pilot projects developed worldwide, where injection of CO2 for sequestration/storage, and Enhanced Oil/Gas Recovery (EOR/EGR) have been ongoing for many years. The well design and completion consideration of such CO2 injected wells, especially pertaining to well integrity, selection of downhole completion equipments, design of pressure containment for high pressure and highly corrosive environment, differs in many ways compared to typical injection wells in the oil field or natural gas storage projects. There are various well integrity failures, which are reported in the literature during drilling and completion of such wells either for EOR or CO2 sequestration projects. The monitoring of CO2 migration within the wells with time is also essential.
In this study, the principle mechanisms involving well integrity issues including caprock and cementing integrity in CO2 injected wells are investigated at various operating conditions, based on comprehensive review of various field cases as published in the literature. The critical factors associated with well design failures, pressure containment, corrosion issues, tubing leakage, cementing problems, and selection of downhole equipments for well completion etc are identified. Based on the study, precise screening criteria are developed that enables the design and completion of CO2 injected wells for EOR and CO2 sequestration; thereby minimizing the chance of integrity failures.
Results for different conditions will be presented and discussed to provide guide lines for mitigating the numbers of theses challenges with an emphasis to the successful design and completion of such wells. The key factors concerning monitoring of CO2 migration with time will be discussed.
Dynamic Well Clean-up Flow Simulation for Field Start-up Planning in the Pyrenees Development, Offshore Western Australia
Authors: Chung C. , Marian D. , Napalowski R. , Thomson J. 
Published: February 2011

Abstract
The Pyrenees development, operated by BHP Billiton, comprises the concurrent development of three oil and gas fields: Ravensworth, Crosby and Stickle. The fields are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin. Seventeen subsea wells, including 13 horizontal producers, 3 vertical water disposal wells and 1 gas injection well have been constructed to date. The project is presently on production with first oil achieved during February 2010.
Due to the normally pressured reservoir conditions, reliable kick-off and clean-up of the long horizontal development wells to the FPSO was heavily dependent upon gas lift. As a result of uncertainty of gas compression availability at field start-up, detailed contingency plans were developed to reduce the reliance on gas lift during field start-up. Identification of feasible contingencies required a thorough understanding of the dynamic flow behaviour of the wells and flowlines during the start-up process.
This paper summarises how a commercial transient multiphase flow simulator was utilised to model well kick-off and clean-up for a number of cases with and without gas lift against initial flowline contents of seawater, diesel or gas. The approach employed to modelling the lateral well sections completed with inflow control devices (ICDs) allowed for an accurate representation of initial and residual drilling mud volumes, annular flow and the impact of the ICDs on the inflow profile.
The primary objective of the dynamic simulation was to identify the requirement for invoking contingency options and to confirm the feasibility of the various options in ensuring a reliable and successful well kick-off without gas lift. A comprehensive analysis of the results contributed to a thorough understanding of the dynamic flow behaviour of the clean-up process. Secondary objectives of the simulation included an estimate of the reservoir drilling fluid (RDF), diesel and flowline contents return rates and volumes to the test separator and an estimate of the time required for each well to clean-up. Conclusions from this work were crucial to contingency planning and proved to be invaluable in successfully executing and optimising well clean-up operations, the field start-up planning and the production ramp-up.
Investigation of SAGD Recovery Process in Complex Reservoir
Authors: Dang Cuong T. , Nguyen Ngoc T. , Bae Wisup , Nguyen Huy X. , Tu Tho N. , Chung Taemoon 
Published: February 2011

Abstract
Alberta's oil sands deposits, with an estimated 1.7 trillion barrels of bitumen in place, account for approximately 40% of the world's bitumen resource. And steam-assisted gravity drainage (SAGD) has opened the door to produce a large number of bitumen reservoirs in Canada. The success of SAGD has been mostly demonstrated by numerical simulation with homogeneous reservoir models. But, this process is very sensitive to reservoir heterogeneities; therefore, it is urgent and necessary to have a comprehensive understanding of the effects of reservoir heterogeneities on SAGD performance for wider and more successful implementation.
This study presented a numerical investigation for evaluating the potential applicability of SAGD recovery process under complex reservoir conditions such as shale barriers, thief zones with bottom and/or top water layers, overlying gas cap and fracture systems in McMurray formation. In order to achieve the general vision and overcome some limitations in literature, these are of factors were evaluated in both individual and simultaneous case studies. Bitumen recovery, average oil production rate, and cumulative steam-oil ratio obtained from thermal simulation were the three main parameters used for evaluation of the attractiveness of bitumen recovery operations. The simulation results indicated that the near well regions are very sensitivity with shale layers and only long, continuous shale barriers (larger than 50m or 25%) can effect to SAGD performance at the above well regions. Besides that, the thief zones have a strongly detrimental effect on SAGD. The results also proved that SAGD recovery process enhanced in the presence of vertical fractures but horizontal fractures were harmful on the recovery. Fracture spacing was not a very important parameter in the performance of steam process in fractured models and the increasing of horizontal fractures extension will reduce ultimate oil recovery in SAGD process. This paper is a worthy guideline for SAGD operations in complex geological reservoirs.