bluuebunny/crossref_metadata_2025 huggingface dataset:
Energy Gain Efficiency in Steam-Assisted Gravity Drainage (SAGD)
Authors: Alharthy Najeeb , Kazemi Hossein , Graves Ramona , Akinboyewa John
Published: February 2011

Steam Assisted Gravity Drainage (SAGD) is a highly popular method for extracting bitumen in situ, and has gained wide acceptance for unlocking Canada's bitumen reserves. Although SAGD is very attractive, it is energy and labor intensive, produces significant quantity of emissions, and requires large water resource and treatment facility. This study addresses these issues by proposing a method to sequester steam boiler exhaust CO2, but focuses specifically on improving the energy gain ratio by reducing the energy input. The proposed method is to augment steam injection with less energy intensive, less expensive, non-condensable gases (CO2 and flue). To quantify the benefits of the method and assess the effectiveness of the process we use energy gain ratio as the main yardstick of the assessment. Five cases of SAGD were simulated with a thermal simulator using a bitumen field data. The study conclusively shows that the process is viable. Specifically the study results in four main conclusions: First, energy gain ratio can be improved by augmenting steam injection with non-condensable gases, for example, if we augment CO2 with steam in a cyclic fashion, energy gain increases by a factor of 1.5 to almost 2. Second, CO2 and flue gas produce the same energy gain ratios and the same recovery factors. Third, intermittent cyclic steam injection performs better than the continuous steam injection in terms of energy gain ratio and recovery factor. Fourth, the injection sequence and the length of the steam and non-condensable gas cycles are important to optimize water and gas breakthrough times. It can also be inferred that reducing steam injection produces economic gains by reducing water usage, fuel requirements for steam generation, and water softening volumes. Also augmenting steam with non-condensable gases reduces green house gas emissions.
Novel Method of Time Controllable Chemistry Water Shutoff Technology
Authors: He Liu , Dan-feng Xiao
Published: February 2011

In late stage of high water cut development period, difficulty in plugging high aquifers increases because the initial pore structure near well bore area has been damaged. Therefore, polymer single fluid plugging technique was developed. Single fluid plugging agent is polymerization initiated by free radical. Reaction time, which is 4-6 hours under normal hole temperature from 40°C to 60°C, is controlled by the half life and the inducement period of initiator. Whereas, in actual application, some wells, such as high temperature deep wells or channeling plugging wells, require longer or shorter gel forming period. Therefore, reaction time control analysis of plugging agent was carried out in order to increase safety and maneuverability of field operation and to expand application field. This paper describes the application of single-fluid water plugging technique in late stage of high water cut development period. Based on the actual condition in oilfield development, the recipe and operation process have to adjust correspondingly to make this technique more serialized and popular. The analysis result on field operation and typical well showed that this water plugging technique could increase oil production and decrease water cut, and satisfied the complicated geological condition of late stage in high water cut development period.
DFA Profiling of Oil Columns With Asphaltene Gradients
Authors: Zuo Julian Y. , Freed Denise , Mullins Oliver C. , Zhang Dan
Published: February 2011

Downhole fluid analysis (DFA) has successfully been used to delineate reservoir attributes such as vertical and lateral connectivity and properties of the produced fluids. The new-generation DFA tools measure GOR, density, light-end compositions of CO2, C1, C2, C3–C5, and C6+, and color that is linearly related to the heavy ends in real time at formation conditions. Color grading analysis in oil columns becomes vital to discern reservoir complexities by means of integrating advanced asphaltene science with DFA Fluid Profiling.

Modeling of asphaltenes and heavy ends of reservoir crude oils is only now becoming possible because of recent advances in the understanding of the molecular and colloidal structure of asphaltenes in crude oils. The Flory-Huggins polymer model has been widely used in modeling of asphaltene precipitation in the oil and gas industry. However, it has been excluded to describe asphaltene gradients in oil columns because the gravitational term requires knowledge of the sizes of asphaltenes which have been unclear until now. On the other hand, typical cubic equations of state (EOS) cannot represent asphaltenes well because of inaccurate asphaltene characterization and the lack of critical points for asphaltenes. Here, we treat the gas-liquid components of crude oil with the Peng-Robinson EOS. Heavy end gradients are treated with the Flory-Huggins formalism explicitly incorporating the size of asphaltene molecules and aggregates. All parameters in the model were related to DFA measurements such as compositions, GOR, density, etc. The variations of gas and oil properties with depth were calculated by the Peng-Robinson EOS based on DFA compositions using specifically developed delumping, characterizing, and OBM correcting techniques. In particular, oil solubility parameters are linearly related to DFA density. Filed case studies prove the value and simplicity of our heavy end treatment. A volatile oil case study shows that colored resins (heavy asphaltene-like resins) are molecularly dissolved in crude oils. Several case studies show asphaltenes are dispersed as nanoaggregates in stable crude. These case studies are in accord with the observations in the recent advances in asphaltene science. Heuristics can be developed form results herein corresponding to prediction of asphaltene gradients. For example, heavy ends (resins, asphaltenes) preferentially reside at the bottom of the oil column both because of gravity and the possible GOR gradients, thus variable solvation strengths. This methodology establishes a powerful new approach for conducting DFA color grading analysis by coupling advanced asphaltene science, the Flory-Huggins grading model, the new workflow and other information with DFA Fluid Profiling to address reservoir connectivity.
Comparison of Permeabilities and Skin Damages Results from Flow Build-up and Injection Falloff Tests in CBM Reservoirs
Authors: Taco Gelber , Kamenar Alberto , Edgoose Jeff
Published: February 2011

Because permeability and skin are important parameters to assess the potential success or failure of a coal seam gas or mining project, it is necessary to implement their measurement at an early stage. For this reason, a suite of Flow Build-up (FBU), Injection Falloff Test (IFT) and Step Rate Test (SRT) tests should be run early in the project but their correct design, execution and interpretation should also be carefully planned.

It is expected that permeability and skin damage outcomes from FBU and IFT tests conducted in the same layer be equal since both employ the same fluids and the same equipment; however, these outcomes are not always the same.

In a Coal field a total 91 tests were run including: 39 FBU, 33 IFT and 19 SRT. Furthermore, in 33 zones the operator conducted sequentially both the FBU and IFT tests. The results indicate that in 42% of these tests, the permeability result from FBU tests differed from the permeability derived from IFT between 0% and 10%, and furthermore, in 28% of these cases, this difference was more than 30%. It was also observed that in 85% of these tests, the skin damage recorded from IFT was higher than from FBU. These outcomes are illustrated with statistics and real examples.

It is the author's view that coal sensitivity to stress is the major contributor to the difference in the permeability results derived from the two procedures since the stress around the borehole is different during the FBU than in IFT. These differences are more frequently seen in low pressure, low permeability seams.

It is also the authors contention that, the higher skin in the IFT test is the result of damaged material (mud cake, drilling fluids and possibly coal fines) being pushed into the formation by the pumping action during the injection period of the IFT test. This effect is noticed more frequently when the well is killed post FBU test to retrieve the testing tool from the well and re-run for the corresponding IFT test.

In summary, with knowledge of the true coal permeability, stress and skin at an early stage by measurement, the project risk of failure could be reduced. The combined effort of the operator who carries out the testing and the analyst who interprets it will help to achieve this aim.
Customized Insulating Packer Fluid Improves Steam Injection Well Integrity
Authors: Turner Jay , Ezell Ryan , MacMillan Brian , Ezzat Dodie
Published: February 2011

Excessive unsupported casing growth at the surface is a problem which could dramatically affect the integrity of the steam injection wells. This problem was recently encountered in a Middle East oil field where severe cement fallback on numerous wells caused excessive casing growth upon injecting steam. Surface steam supply lines could accommodate up to 4 ft (1.2 meters) of casing growth, but the wells with poor cement bond experienced up to 8 ft of wellhead movement. Remedial cement placement was not an acceptable option for injection wells that require perforated casing. An alternative economical method to control casing growth was therefore needed.

Fresh water was normally placed in the annulus, which evaporated and released to the atmosphere due to the very high steam temperature (ca. 575°F/300°C). Heat transfer to the casing was very high, causing the excessive casing expansion. Controlling this heat transfer will limit wellhead movement while retaining the energy in the steam for more efficient reservoir heating and oil recovery.

A high temperature insulating fluid was custom-designed for these subject wells. The solids-free water-based fluid had low inherent heat transfer and was gelled with a unique stable inorganic viscosifier to prevent convection at the target temperature. Preventing convection is a key factor in reducing heat transfer. After four days of steam injection, the operator reported that wellhead movement was half of that in offset wells completed with fresh water as the packer fluid. This paper will present and discuss the lab and field data for the new insulating fluid which offers several advantages in reliability and performance for extreme temperature applications such as the geothermal and steam injection wells.
Logging-While-Drilling in Unconventional Shales
Authors: Market Jennifer , Quirein John , Pitcher Jason , Hinz David , Buller Dan , Al-Dammad Chaled , Spain David , Odumosu Tobi
Published: February 2011

Unconventional shale environments have traditionally been evaluated with wireline logging tools. Recently, it has become more common to evaluate these wells with logging-while-drilling tools because of challenges such as wellbore stability problems that make it risky to leave the hole uncased long enough to run wireline. This paper discusses when it may be appropriate to log unconventional shale environments with LWD tools, the services that are available, and the possible advantages of real-time data while drilling. It also describes the possible differences in the LWD and wireline measurements, including such factors as openhole vs. cased hole data acquisition, time-lapse effects, and anisotropy responses of sonic, resistivity, and nuclear tools.

The paper presents examples from the Bakken and Haynesville shales, including azimuthal resistivity, density, caliper, and sonic data. Special considerations for interpreting logs in these environments are discussed, particularly regarding log interpretation in high angle wellbores. Finally, details about the optimization of the logging program and tool configurations are provided for ideal data acquisition in unconventional shale environments.
Plug Indicator System Prevents Calculated Volume Errors in Subsea Casing for Primary Cementing Operations
Authors: Caldwell Rebecca , Scott Thad
Published: February 2011

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

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

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

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

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

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

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

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

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

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

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.
Solids-Free Viscoelastic Fluid Loss Pills and Dynamic Underbalance Improve Productivity from Newly Perforated Wells
Authors: Arangath R. , Babalatirov Y. , Griffith M. , Umirbayev A.
Published: February 2011

Many operators in Kazakhstan are producing from carbonate reservoirs with fairly low permeability and porosity with the presence of dominant natural fractures. The completion and perforation of the reservoir are critical phases during which special attention must be placed on the well cleanup to obtain the maximum hydrocarbon productivity. Wells in the tight carbonate formation of certain fields in western Kazakhstan have historically been perforated in overbalance conditions or in static underbalance conditions that require killing the well immediately after the perforation for installing the permanent completion. After the permanent completion has been put in place, an acid wash must be performed to remove all the damage induced by the killing operation and the perforating debris. Both ways of perforating the wells expose the reservoir to potentially damaging fluids during and after the perforation. The exposure time of these fluids can be prolonged if adverse meteorological conditions are encountered. The damaging fluids can significantly impair the productivity by blocking the newly perforated tunnel, as well as by filtering through the natural fractures, which in turn makes it very difficult to remove even after as acid wash. As a result, the wells do not produce to their full potential.

A new perforating approach utilizing a dynamic underbalanced technique, in conjunction with a solids-free, viscoelastic-based, fluid loss pill, was introduced in several new wells in western Kazakhstan for a major operator. The fluid loss pill was designed to be solids-free and to be easily broken, leaving no residue downhole. There were four main requirements for the fluid pill:

Effective—capable of stopping or minimizing completion brine losses at bottomhole static temperatures (BHSTs) up to 137°C. Degradable—easy to clean and with minimal residual damage to the reservoir or the perforations. Compatible—fully compatible with reservoir fluids and any well service fluids. Solids-free—making the post-completion cleanup operation easy.

The carbonate reservoir where this new approach was utilized has permeabilities varying from 6 to 38 mD, while the present reservoir pressure is approximately 4,200 psi at the reference depth of 3550 m. The new perforation approach allowed obtaining a cleaner perforation tunnel, increasing the average production compared with wells draining from the same reservoir that were completed with the traditional technique. The average production obtained with the new approach is approximately double that of the conventional technique. This has been verified on a campaign carried out on 11 wells, all located in the same area of the field, four of which were completed with the new perforation approach. Several other treatments have been performed and have indicated similar trends in production.
An Improved Adjoint Sensitivity Computation for Multiphase Flow Using Wavelets
Authors: Awotunde Abeeb A. , Horne Roland N.
Published: February 2011

In history matching, one of the challenges in the use of gradient-based Newton algorithms such as Gauss-Newton and Levenberg-Marquardt in solving the inverse problem is the huge cost associated with the computation of sensitivity matrix. Although the Newton type of algorithm gives faster convergence than most other gradient-based inverse solution algorithms, its use is limited to small and medium-scale problems in which the sensitivity coefficients are easily and quickly computed. Modelers often use less efficient algorithms such as conjugate-gradient and quasi-Newton to model large-scale problems because these algorithms avoid the direct computation of sensitivity coefficients. To find a direction of descent, such algorithms often use less precise curvature information that would be contained in the gradient of the objective function. Using a sensitivity matrix gives more complete information about the curvature of the function, however this comes with a significant computational cost for large-scale problems.

An improved adjoint sensitivity computation is presented for time-dependent partial differential equations describing multiphase flow in hydrocarbon reservoirs. The method combines the wavelet parameterization of data space with adjoint sensitivity formulation to reduce the cost of computing sensitivities. This reduction in cost is achieved by reducing the size of the linear system of equations that are typically solved to obtain the sensitivities. This cost-saving technique makes solving an inverse problem with algorithms such as Levenberg-Marquardt and Gauss-Newton viable for large multiphase flow history matching problems. The effectiveness of this approach is demonstrated for two numerical examples involving multiphase flow in a reservoir with several production and injection wells.
Successful Case Histories of the Conformance-While-Fracturing Technique in Egyptian Western-Desert Reservoirs
Authors: Ali Ahmed , Yassine Rami , Tawakol Moataz , Aal Ezz Abdel , Khalek Tamer Abdel , Hamdy Ahmed
Published: February 2011

Hydraulic fracturing has proven to be extremely successful in the western desert of Egypt. Approximately 85% of production in this area results from this stimulation technique, specifically in the reservoirs of interest documented in this paper. However, a deterrent to fracturing in many cases has been the proximity of the producing zones to underlying (or overlying) water zones, either located near the water-oil contact or hydrocarbon zones adjacent to water-bearing zones. In the absence of geological barriers, the fracture height can grow uncontrolled during a fracturing treatment into the water-bearing interval and cause unwanted water production. Excessive water production threatens the economics of a well by: shortening its production life, increasing disposal and lifting costs, boosting the fines migration, and increasing the rate of tubular corrosion and scale buildup. Many times, in marginal fields, these can be sufficient reasons to consider not fracturing.

This paper presents case histories where wells were hydraulically fractured using conventional techniques resulting in higher than 60% water cut (even as much as 100% in one case); while with the use of the conformance-while-fracturing (CWF) method, the water cut obtained was as low as 4%, even when the adjacent water zones were within 20 ft of the perforations. This technique provides a tremendous boost to the economics and an effective solution (increasing recoverable reserves from these wells by allowing the hydrocarbons to be produced almost water-free) to a field otherwise plagued with water production. The CWF technique incorporates a relative-permeability modifier (RPM) in the fracturing-fluids design. The RPM provides a reduction in effective permeability to water without significant changes to the relative permeability to oil. This paper discusses the geological and reservoir parameters of the wells and zones of interest, the properties of the RPM, the CWF job-design considerations (and the associated challenges to the job design), its field applications, and post-fracturing results in comparison to offset wells fractured conventionally in the same reservoir and at the same level. It is envisaged that CWF techniques will prove to be beneficial to other operators faced with similar production challenges.
Virtual Metering System for Oil and Gas Field Monitoring Based on a Differential Pressure Flowmeter
Authors: da Paz E. F. , Baliño J. L. , Slobodcicov I. , Filho D. F.
Published: February 2011

In this paper, a virtual metering system (VMS) for oil and gas monitoring based on a differential pressure transducer (orifice plate, venturi or nozzle) is presented. The model for the measuring device considers one-dimensional subsonic flow of gas, oil and water. Oil and water are considered to flow with a single velocity (homogeneous flow), while relative velocity between the gas and liquid phases is taken into account by means of a slip ratio calculated with Chisholm's correlation. Neglecting friction, mass transfer, compressibility and variations in the slip ratio along the converging portion of the flowmeter, it is possible to integrate the mass and conservation equations to obtain a generalization of the mass flow versus pressure drop relationship corresponding to a differential pressure flowmeter for multiphase flow. The total mass flow depends on a set of variables evaluated at operating condition: density and viscosity of the liquid and gas phase, mass quality, pressure drop across the flowmeter and geometry (contraction area and beta factor).

The determination of the fluid variables at operating condition is made by using a black oil model and a set of variables at standard condition that characterizes fluid composition, being the most important GOR, BSW and densities of the individual phases.

An experimental campaign was carried out at different wells located at Urucu field, Solimões basin (Amazonas, Brazil), using orifice plates. The total mass flow rate and the volumetric flows for each individual streams at standard condition calculated with the VMS showed an excellent agreement with the experimental data.
Success Story of Downhole Fluid Sampling in a Very Challenging Environment in the Gulf of Thailand
Authors: Kanjanavasoontara C. K. , Daungkaew Saifon , Yimyam Nitipong , Platt Christopher , Houtzager Fred
Published: February 2011

Traditionally, the Gulf of Thailand (GoT) has been known for high temperature, small borehole size, variable CO2, and highly compartmentalized reservoirs. In particular, it is a very challenging environment for Wireline Formation Testers (WFT). Owing to cost constraints, since the start of exploration and development campaigns in this area, usage of newer technologies has been highly selective. However, this has been changed significantly in the past few years where the right WFT technology has been applied to the right environment. This paper is the first to present a work process to derive clean fluid sampling in the very challenging environment of the GoT.

Time per station used to collect downhole fluid samples using WFT has been a major concern for a costly offshore operation. In addition, borehole stability is also another factor limiting WFT time. Given the time constraint, collected fluid samples usually have high drilling mud filtrate contaminations, in the ranges of 25 to 85wt%, and have not been suitable for further laboratory analysis and field development purpose. Balancing between the time used for fluid sampling and the quality of the collected fluid samples is not a simple task to manage.

This paper shares a successful story of downhole fluid sampling in exploration wells for one of the operators in the GoT. Instead of using a conventional probe with one Downhole Fluid Analyzer (DFA), the concentric shaped probe with two synchronized pump-out modules and two DFAs are used in this case. However, this is not as simple as other fields already presented in the literature because an unconsolidated sand character introduced complications into this sampling technique. Several attempts have been developed to make focused sampling work in these challenging environments. At the end, "Less than 5% OBM contaminated samples in oil reservoirs are successfully achieved in a timely manner." The average time used per each sampling station is approximately 30 minutes. This paper will also discuss the advantages and disadvantages for each technique applied and the final results. In addition, more improvements have been suggested to enhance this focused sample technology in more complex fluids, such as gas condensate reservoirs to make sure that less contaminated fluid sample can be collected in the limited time per station.