bluuebunny/crossref_metadata_2025_split huggingface dataset:
Best Practices in Designing HP/HT Cement-Plug Systems
Authors: Syed Haidher 
Published: September 2008

Abstract
Cement plugs are required mainly to abandon a well or zones or to kick off new drilling or completion efforts. Almost all ultra-HPHT exploratory wells and all other non-producing wells (which have ended their useful life) require abandonment with cement plugs.
Cement plugs for HPHT and ultra-HPHT application require conform to the acceptable fluidity, ultimate strength and desired properties. The placement environment exacerbates the challenges of system design, especially if the well is deviated or approaches horizontal.
Achieving successful cement plugs in highly deviated or in horizontal wells in HPHT and ultra-HPHT conditions, especially in brine environments, requires special designs and techniques. The requirements include modified testing procedures and products that can withstand bottomhole pressure and temperature conditions for the entire life of the well. Furthermore, setting a cement plug downhole in a deviated HPHT well may require special equipment and logistics.
As an example of the complications in HPHT wells, on the east coast of India bottomhole static temperatures are as high as 507°F and mud weight can vary between 14 and 19 ppg in deviated wells. Experience has shown that conventionally calculated bottomhole circulating temperature alone is inadequate to determine the working temperature downhole. However, with the help of computer-aided temperature simulation and all the above techniques, many successful cement plug jobs have been executed under these difficult conditions.
Using case histories for illustration, this paper will share best practices developed from 4 years of experience designing and placing cement plugs in 8 HPHT and ultra-HPHT wells successfully. These practices will include HPHT cement plug design considerations, modified lab testing procedures, special placement techniques and product choices.
Sustainable Spatial Architecture for Geo Engineering Data and Workflows
Authors: Kozman Jess , Ripley Thomas 
Published: September 2008

Abstract
Spatial attributes are pervasive in petroleum engineering data. Solutions that create a competitive advantage by effectively using this data require a sustainable architecture with documented workflows to increase user confidence and alleviate engineering risk. The components of a sustainable spatial architecture are; data accessibility, a standard data model, portal consumption and Geographic Information System (GIS) access, and data maintenance and business rules. A full lifecycle solution for management of spatial attributes includes collection from field and public domain sources, quality assessment and control, storage in standardized data models, distribution to analysis applications, and capture in knowledge management and audit systems. Each component and lifecycle stage can impact financial performance of the organization using the geotechnical data. Site assessments and a standard methodology for documentation of processes and components were used to compare solutions and value statements for multiple domestic and international operators.
The assessments found that accessibility by end-users impacts quality, accuracy, and confidence related to spatial data. The economic impact of this component is lack of end-user confidence in data tools, and the cost of re-acquiring data. The data model provides feature class intelligence, naming conventions, and attribute accessibility, a standard taxonomy, and a method to move petroleum engineering data into a world of points, lines and polygons. The utility of this component is measured in lost opportunity costs of incomplete analysis, and inconsistent data causing poor drilling decisions. Portal access through service oriented architectures delivers visual and automated quality control of multiple data sources and is documented to save engineering time spent on data discovery and manipulation. Business rules serve to formalize data ownership and governance and support an intelligent synchronization process that maintains validated corporate spatial data, providing a single source of truth that reduces risk for engineering decisions.
Successful solutions require all described components plus repeatable and auditable workflows for extracting well, reservoir and seismic spatial attributes from robust industry standard models. This study allows petroleum engineers to determine the maturity of their current and legacy solutions, and plan for goals of mitigating risk, improving workflows, and lowering costs within a scalable, sustainable Spatial Data Architecture.
A New Solution to Restore Productivity of Gas Wells With Condensate and Water Blocks
Authors: Bang Vishal , Pope Gary A. , Sharma Mukul M. , Baran Jimmie R. , Ahmadi Mohabbat 
Published: September 2008

Abstract
During production from gas condensate reservoirs, significant productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluid. Many of these gas reservoirs also have some water accumulation near the wells. This adds significantly to the total liquid blocking.
Experiments were conducted using both outcrop sandstone and reservoir cores to measure the effect of liquid blocking on gas relative permeability. A chemical treatment was developed to reduce the damage caused by condensate and water blocking. The treatment is composed of a fluorinated material delivered in a unique and optimized glycol-alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral wet and increases the gas relative permeability.
The increase in gas relative permeability was quantified by comparing the gas relative permeabilities before and after treatment. Improvements in the gas relative permeability by a factor of about 2 were observed. The alteration of wettability after the chemical treatment was evaluated by measuring the USBM wettability index of treated reservoir cores. Measurements show a significant amount of the surfactant is adsorbed on the rock surface, which is important for the durability of the treatment.
Many attempts have been made to develop effective chemical treatments to mitigate the damage caused by condensate and/or water blocking with little success until now under realistic reservoir conditions. Using inexpensive, safe and effective solvents was one of the keys to the success of our new approach. Others have mostly tried reactive materials that are subject to complications in downhole applications. We use a non-reactive, nonionic polymeric surfactant that does not have any of these problems and is robust over a wide range of temperature, pressure, permeability and brine salinity.
We have developed a chemical treatment for liquid blocking that shows great potential to increase production from gas condensate wells. Compositional simulations indicate the economics of this treatment process are likely to be very favorable.
Investigation of Economic Incentives for CO2 Sequestration
Authors: Ghomian Yousef , Urun Mehmet , Pope Gary A. , Sepehrnoori Kamy 
Published: September 2008

Abstract
We have completed an exploratory economic analysis based upon systematic compositional simulations of CO2 EOR to establish how much and what type of economic incentive might be needed to encourage oil companies in the U.S. to store CO2 in oil reservoirs. The economic analysis took into account factors such as capture and transportation costs. In order to quantify the effect of flood performance, various simulations were performed by employing different reservoir types, well spacing, and injection schemes. Experimental design and method of response surfaces along with Monte Carlo simulations were utilized to perform this study in a systematic, efficient and accurate manner. Combinations of reservoir parameters and economic factors were studied to achieve comprehensive understanding of the financial performance of coupled CO2 sequestration and EOR projects. Possible CO2 credits were also quantified in a probability based distribution functions considering various uncertain economic and geologic characteristics in different projects.
A New Method of Well-Test Analysis in Naturally Fractured Reservoirs Based on Elliptical Flow
Authors: Igbokoyi Alpheus O. , Tiab D. 
Published: September 2008

Abstract
Well test analysis in naturally fractured reservoirs is generally based on the radial flow model, even when it is widely believed that such reservoirs are anisotropic. The radial flow model is however only applicable to purely homogeneous system and long time solution. It cannot provide a complete formation analysis in a reservoir that exhibits anisotropy.
This study therefore presents a new method of estimating permeability anisotropy in naturally fractured reservoirs. Maximum and minimum permeability are obtained in one well test. The maximum permeability is attributed to the large scale fractures in the system while the minimum permeability may be due to the small scale fractures orthogonal to the large scale fractures. In a situation where the fractures are orienting in one direction, the minimum permeability will reflect the matrix permeability. The type of flow path developed (narrow or wide flow path) can also be predicted. This is useful in predicting the direction of fluid flow.
Application was made to four field examples, one of which was an interference test. The interference test was used as a validation process. The results obtained are in agreement with that of a conventional interference test method of analysis.
Modeling Foam Displacement with the Local Equilibrium Approximation: Theory and Experiment Verification
Authors: Chen Q. , Gerritsen M. G. , Kovscek A. R. 
Published: September 2008

Abstract
The gas mobility control aspects of foamed gas make it highly applicable for improved oil recovery. Gas bubble size, often termed as foam texture, determines gas flow behavior. A population balance model has been developed previously for modeling foam texture and flow in porous media. The model incorporates pore-level mechanisms of foam bubble generation, coalescence, and transport. Here, we propose a simplified foam model to reduce computational costs. The formulation is based on the assumption of local equilibrium of foam generation and coalescence and is applicable to high and low quality foams. The proposed foam model is compatible with a standard reservoir simulator. It provides a potentially useful, efficient tool to predict accurately foam flows at the field scale for designing and managing foamed-gas applications.
There are three main contributions of this paper. First, the population balance representation of foam generation by gas-bubble snap off is modified to extend the capability of the population balance approach to predict foam flow behaviors in both the so-called high-quality and low-quality regimes. Second, a simplified population-balance model is developed and implemented with the local-equilibrium approximation. Third, foam displacement experiments in a linear sandstone core are conducted to verify the proposed model. A visualization cell is employed to measure the effluent foam bubble sizes for a transient flow as well as to estimate the in-situ foam bubble sizes along the length of the core during steady flow. Additionally, the evolution of aqueous phase saturation is monitored using X-ray computed tomography (CT) and the pressure profile is measured by a series of pressure taps. Good agreement is found between the experimental results and the predictions of the simplified model, with a minor mismatch in the entrance region.
Equivalent Skin Factors for Nonuniformly Damaged Horizontal and Multilateral Wells
Authors: Yildiz Turhan 
Published: September 2008

Abstract
In the first part of this study, we scrutinize the equivalent skin concept used to emulate the influence of uneven formation damage on the performance of horizontal wells. Rigorous 3D multisegment well models are used to simulate the local changes due to nonuniform formation damage around wellbore accurately. We show that the simple models, presented in the literature, to compute equivalent skin factors are quite limited in their accuracy.
Equivalent skin factor resulting from nonuniform formation damage around a horizontal well, in general, is influenced not only by the static damage distribution itself but also by many reservoir and wellbore variables. A convoluted interaction of well location, distance to reservoir boundaries, reservoir boundary type, formation thickness, well length, extent and nature of static formation damage itself, production time, and the contrast between the flux distributions around damaged and undamaged wells affects and controls the equivalent skin factor around horizontal wells.
In the second part of the study, we investigate the uneven formation damage around multilateral wells. Our investigation concludes that, as far as the equivalent skin factor values are concerned, the multilateral cannot be represented as an extension of horizontal wells. The interaction between the laterals affects the flux distribution around the laterals which in turn influences equivalent skin factors. Commingled production from duallateral systems changes the nature and size of equivalent skin in comparison with equivalent skin factors resulting from individual and separate productions from each lateral. In a duallateral system, the contrast in the individual lateral lengths may have a strong impact on the equivalent skin factors for both laterals.
Smart Chemical Systems for the Stimulation of High-Water-Cut Heavy Oil Wells
Authors: Samir Mohamed Ahmed , Elnashar Islam , Samuel Mathew , Jemmali Mohamed 
Published: September 2008

Abstract
The Nukhul formation in the Gulf of Suez is highly fractured, depleted reservoir producing 9 to 10 API gravity heavy oil at water cuts up to 98%. Stimulation is required to enhance oil production and extend the life of the field. An inherent problem with these wells is poor acid placement during matrix acidizing, especially in reservoirs with high-permeability contrasts. Conventional acidizing results in the stimulation of water zones, and misses targeted oil zones. The high viscosity and low mobility of the Issran field heavy oil, in contrast with the strong mobility and low viscosity of the formation water, makes the problem even more pronounced.
To temporarily plug the water zones and effectively stimulate oil zones with chemical diversion, a new surfactant-based chemistry has been introduced. When mixed in brine, it forms a high viscous gel. The gel maintains its viscosity when contacting water and breaks down when contacting oil, thus temporarily plugging the zones of high water saturation. When mixed in acid, the new system will stimulate and divert automatically based on in-situ gellation mechanism related to acid spending; thus achieving uniform distribution. In addition, the new acid system has a unique inherent property to limit acid penetration in high water saturation zones, while enhancing deeper penetration in high oil saturation layers.
Conventional acid treatments have a low success rate in the Nukhul formation. More than 50% of the stimulated oil wells turned into 100% water producers. The new stimulation treatment fluids and placement techniques improved oil production and lowered WCs. Water cut before acid treatment ranged from 90% to 98%. After the treatment, water cuts lowered to the range from 40% to 75%, and post-oil production increased by as much as three- to eightfold.
This study assesses the performance of the placement techniques and fluids used in the stimulation of the Nukhul formation based on field data. It also quantifies the economical added value resulting from the usage of the surfactant-based systems with respect to conventional matrix stimulation fluids.
The Impact of Gravity Segregation on Multiphase Non-Darcy Flow in Hydraulically Fractured Gas Wells
Authors: Dickins Mark I. , McVay Duane A. , Schubarth Stephen K. 
Published: September 2008

Abstract
Multiphase and non-Darcy flow effects in hydraulically fractured gas wells reduce effective fracture conductivity. Typical proppant pack laboratory experiments are oriented in such a way that phase segregation is not possible, which results in mixed flow. In this work, reservoir simulation modeling was used to determine the impact of gravity segregation. Gravity segregation is commonly ignored in design and analysis of hydraulically fractured gas wells. We found that by ignoring segregation, effective fracture conductivity can be underestimated by up to a factor of two. Hydraulic fracture treatments can be designed more effectively if effective fracture conductivity is known more accurately.
ASP Chemical Flooding Without the Need for Soft Water
Authors: Flaaten Adam K. , Nguyen Quoc P. , Zhang Jieyuan , Mohammadi Hourshad , Pope Gary A. 
Published: September 2008

Abstract
Alkaline-surfactant-polymer (ASP) flooding using conventional alkali requires soft water. However, soft water is not always available, and softening hard brines may be very costly or infeasible in many cases depending on the location, the brine composition and other factors. For instance, conventional ASP uses sodium carbonate to reduce the adsorption of the surfactant and generate soap in-situ by reacting with acidic crude oils; however, calcium carbonate precipitates unless the brine is soft. A form of borax known as metaborate has been found to sequester divalent cations such as Ca++ and prevent precipitation. This approach has been combined with the screening and selection of surfactant formulations that will perform well with brines with high salinity and hardness. We demonstrate this approach in this paper by combining high performance, low cost surfactants with co-surfactants that increase salinity and hardness tolerance with metaborate. Chemical formulations containing surfactants and alkali in hard brine were screened for performance and tolerance using microemulsion phase behavior experiments and crude at reservoir temperature. A formulation was found that with an optimum salinity of 120,000 ppm TDS (with 6600 ppm divalent cations) that performed well in core floods with high oil recovery and almost zero final chemical flood residual oil saturation. Additionally, chemical formulations containing sodium metaborate and hard brine gave nearly 100% oil recovery, with no indication of precipitate formation. Metaborate chemistry was incorporated into the mechanistic UTCHEM simulator and the simulator was then used to model the core floods. Overall, novel ASP with metaborate performed comparable to conventional ASP using sodium carbonate in soft water, demonstrating advancements in ASP adaptation to hard, saline reservoirs without the need for soft brine, which increases the number of oil reservoirs that are candidates for enhanced oil recovery using ASP flooding.
Responsive Cementing Material Prevents Annular Leaks in Gas Wells
Authors: Bouras H. , Doumaz N. , Bellabarba M. , Caceres E. , Mananga S. , Le Roy-Delage S. , Abd-El Aziz M. Gamal , Benberber M. Rebbou 
Published: September 2008

Abstract
In a traditionally cemented well, the integrity of the cement sheath surrounding the casing, and the bond between the cement and the formation or casing are essential components of hydraulic isolation. A well-cemented casing is designed to maintain hydraulic isolation throughout the productive life of the well and after abandonment. With advances in cementing technology, slurries have been designed that result in cement sheaths that can resist planned wellbore stresses without failure. Once the cement has set, however, the fixed set-cement properties do not address stresses that have not been planned for, and that may ultimately result in cement sheath failure.
This study considers the case of well construction as part of a new gas field exploration in Algeria. Wells drilled in this area have been prone to developing annular gas leaks in the weeks and months following cementing operations. To prevent the loss of isolation and reestablish hydraulic integrity in the event of cement failure, a new cement-based sealant was incorporated into the well construction plan. This reactive material responds to hydrocarbon leaks that occur because of fissures in the cement, debonding of cement from the formation or the development of a microannulus between the cement and the casing. These leaks trigger a self-healing response, sealing the leak path, and restoring well integrity. Using this sealant material has reduced the incidence and likelihood of leaking wells in an area where such problems are common, and eliminated the potential time and cost associated with leak remediation.
Bridging the Gap Between Real-Time Optimization and Information-Based Technologies
Authors: Brulé Michael , Charalambous Yanni , Crawford Mark L. , Crawley Charles 
Published: September 2008

Abstract
For the past several years, the problem of reducing time-to-decision in field operations and capital projects has been repeatedly described and analyzed in qualitative and anecdotal terms. In this paper, we take an engineering approach to measure and understand the problem in quantitative and fact-based terms. We first review the mission of the SPE IT Technical Section–Oilfield Integration (SPE ITTS OI) subcommittee. Several contexts of oilfield integration and their role in Digital Oilfield of the Future (DOFF) initiatives are identified. We discuss the results of our study, and compare the results with those from other studies conducted by the SPE and also by two integrated oil companies (IOCs). We address the goal of "reducing time to decision," and show how even the most basic data-integration gaps can slow decisions with great economic impact. In information management and decision-making, the mondegreen "data commute" is the biggest problem area. The data commute absorbs over half the time that engineering and operations personnel could be spending making crucial decisions to effectively manage E&P assets. We review some case studies and their economic impact. Beyond "saving half of an engineer's time," several other more subtle gaps in the industry's current modeling and integration approaches are identified and evaluated. We conclude with showing how some of these gaps have been filled in other industries outside of oil & gas, and cite some examples that could be applicable in production surveillance and optimization.