bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparison of Well Productivity between Vertical, Horizontal and Hydraulically Fractured Wells in Gas-Condensate Reservoirs
Authors: Hashemi A. , Gringarten A. C. 
Published: January 2008

AbstractGas condensate reservoirs usually exhibit complex flow behaviors due to the build-up of condensate banks around the wells when the bottomhole pressure drops below the dew point. The liquid phase accumulation in the near-wellbore region forms a ring that reduces the gas relative permeability. As a result, gas production decreases and the liquid phase which is a significant part of the value of the field remains in the reservoir.Various solutions have been implemented in order to remediate such a productivity loss. They include drilling horizontal wells instead of vertical wells1-3, hydraulically fracturing vertical wells before or after the development of the condensate bank, and acidizing after the condensate bank has formed4-14.In this work, we used reservoir simulation to quantify the increase in well productivity from different remediation solutions and assess their effectiveness. The empirical correlations needed to model non-Darcy flow and capillary number effects, which are among the main parameters that control gas condensate well performance, were calibrated with actual well test data.As should be expected, we found that horizontal wells and hydraulically fractured vertical wells improve well productivity. The degree of productivity enhancement, however, depends on well and reservoir parameters such as horizontal well lengths, permeability anisotropy, fracture length and fracture conductivity. Different simulation models were run above and below the dew point pressure at the same reservoir and flow conditions. The results of our simulations show that horizontal wells enhance productivity significantly below the dew point. Performance improvement with hydraulic fractures, on the other hand, depends on facture length and fracture conductivity.
Recommended Practice for Overbalanced Perforating in Long Horizontal Wells
Authors: Chang F. F. , Mathisen A. M. , Kâgeson-Loe N. , Walton I. C. , Svane G. , Midtbø R. E. , Bakken I. , Rykkje J. , Nedrebø O. 
Published: January 2008

Abstract
Completing offshore horizontal wells often requires killing the wells immediately after perforating before pulling the gun out of the hole and installing the rest of the completion hardware. Perforating practice varies from operator to operator. Some operators prefer to perforate in a clear fluid and spot a kill fluid for well control afterwards. While others perforate directly in a solid containing kill fluid. Both methods are done in overbalance. A two-year extensive research program was carried out to quantify the formation damage caused by these perforating practices.
The testing was conducted under downhole conditions in a large-scale laboratory setup, which physically simulates the wellbore and the reservoir, as well as the perforating and production processes. Tests were designed to study the pressure dynamics during perforating; to gain understanding of the effect of the perforating pressure dynamics on fluid loss control and formation damage; to select the most suitable kill fluid; and finally to provide overbalanced perforating design guidelines for production optimization.
The core test results showed that perforating design not only determines the skin damage caused by debris and grain crushing, but also plays a key role in controlling fluid loss, which strongly influences the permeability and productivity of the reservoir. Therefore, proper perforating design not only involves selecting the right shaped charges and gun hardware, but also it needs to take into account the perforating pressure dynamics, fluid formulation, and completion sequence.
In addition to the core flow testing, petrographic studies were performed on the perforated core samples to allow visual observation of the rock alterations caused by perforating and kill fluids.
This paper presents the findings in formation damage mechanisms during overbalanced perforating and kill processes and provides recommended practices in both job design and fluid selection for this type of operation in long horizontal wells.
Learning the Right Lessons—The Key to Delivering a Record ERD Well in the Caspian
Authors: Kidd G. N. , Tukshaitov A. , Najafov F. 
Published: January 2008

Abstract
The Operator has been developing oil reserves from an Early Oil Production (EOP) facility in the Caspian Sea since 1997. Because of the location of the platform, accessing the Northern reserves required the implementation of an ERD drilling program. Four ERD wells have been drilled since 2001. The last well was delivered on time and on budget to a measured depth of 7472m, and a step out of 6,315m making it the longest well drilled in the Caspian basin to date.
This paper summarizes progress that has been made towards delivering successful ERD wells in the difficult Caspian basin. It describes how the basis of design for ERD wells 1 and 2 drew on the lessons from other projects including Wytch Farm, and why that philosophy did not produce the planned results.
The paper will highlight the lessons learned applied to the third well, which was delivered with the majority of the well design objectives satisfied but over budget and with a significant amount of Non Productive Time (NPT). The paper will focus on the planning and execution of the fourth well, detailing how the right lessons, key technologies, key drilling practices, and right resources were applied to deliver the longest ERD well in the Caspian on time and within budget with a total NPT of less than 16%.
The key components of success will be explored in detail. These include implementation of new technologies, including "stress cage", closed end conductor driving, cuttings flow metering, formation pressure LWD tools and"Geosteering" to manage geological uncertainty and allow excellent execution of the plan. The paper will discuss how a systematic, rigorous planning approach was applied. The modeling and simulation techniques critical to success used by the onshore planning team and also employed offshore using real time data for critical decision making will also be described
Finally the process whereby this plan was handed over to the execution team offshore will be explained illustrating the importance of engaging the offshore team in the planning of this type of well. This was linked to the whole team's involvement in the development of the practices and procedures and use of the Technical Limit process on simpler wells before utilising them where there was no room for error.
In conclusion, the paper will show how an integrated, multidisciplinary team can overcome significant technical challenges with the right processes, people, technology and support to deliver a successful well.
Applications of Sequence Stratigraphy and Geological Modeling to Mature Field Development: Khalda Ridge, Western Desert Egypt
Authors: Mahgoub I. S. , Mowafi K. , Hussein H. , Wehr F. 
Published: January 2008

Abstract
A joint study integrating geological and engineering data was undertaken tolocate infill wells and to optimize the injection pattern in Hayat-Yasser, Kenzand Salam fields in the western desert of Egypt. The focus of this work was theCretaceous Bahariya and Abu Roash "G" formations which are sedimentologicallydescribed as estuarine to shallow-marine sandstones deposited in a mixedclastic-carbonate ramp setting.
All major seismic surfaces were remapped using pre-stack time-migrated data.A detailed sequence-stratigraphic framework based on core description andpetrophysical analysis provides the static reservoir framework. These geologicdata are incorporated in a detailed 3D geological model, which forms the basisfor all structural and reservoir mapping.Pressure and production datawere analyzed within this framework, in order to identify potential infill andrecompletion opportunities as well as potential improvements in changingwater-flood pattern from peripheral to internal and to dedicated injection.
Rapid Flash Calculations for Compositional Modeling
Authors: Li Y. , Johns R. T. 
Published: January 2008

Abstract
The computational time for conventional flash calculations increasessignificantly with the number of components making it impractical for use inmany finely-grided compositional simulations.Previous research toincrease flash calculation speed has been limited to those with zero binaryinteraction parameters (BIPs) or approximate methods based on an eigenvalueanalysis of the binary interaction matrix.Practical flash calculations,however, nearly always have some nonzero BIPs.Further, the accuracy andspeed of the eigenvalue methods varies depending on the choice and number ofthe dominant eigenvalues.
This paper presents a new method for significantly increasing the speed offlash calculations for any number of nonzero BIPs.The approach requiresthe solution of up to six reduced parameters regardless of fluid complexity orthe number of components and is based on decomposing the BIPs into twoparameters using a simple quadratic expression.The new approach is exactin that the equilibrium phase compositions for the same BIPs are identical tothose with the conventional flash calculation; no eigenvalue analysis isrequired. Further, the new approach eliminates the Rachford-Riceprocedure and is more robust than the conventional flash calculationprocedure.We demonstrate the new approach for several example fluids, andshow that speed up by a factor of about 3 - 20 is obtained over conventionalflash calculations depending on the number of components.
Exploration Drilling in the Barents Sea; Prevailing Zero Discharge Regime, Challenges and Learning From Recent Exploration Drilling
Authors: Paulsen J. E. , Hoset H. , Rørhuus T. , Larsen V. , Alm D. , Birkeland Ø. , Marker R. 
Published: January 2008

Abstract
The Barents Sea is an environmentally important ecosystem defined as part of the Arctic. The Norwegian environmental regulation is particular strict for this area, a zero discharge regime prevails. This paper describes the challenges of entering the area for exploration drilling. With reference to a recent operation (2005) a presentation of how the challenges were resolved is given. New procedures and new techniques were implemented to achieve compliance with performance expectations. The succeeding experience lead to important learning that has implications for future exploration drilling in such areas.
A Deepwater Monitoring Design and Program to Assess the Environmental Fate and Effects of Paraffin Based Muds and Cuttings off Sarawak and Sabah (Malaysia)
Authors: Ray J. P. , James B. M. , Dorn P. B. , Farmayan W. F. , Hj-Kip S. , Hii K. K. , Rhodes I. 
Published: January 2008

Abstract
Sarawak Shell Berhad and Sabah Shell Petroleum Co Ltd are companies of the Royal Dutch/Shell group of companies operating in Malaysia under a Production Sharing Contract arrangement. Current drilling activities are located offshore the states of Sarawak and Sabah. Due to difficult downhole drilling conditions, the use of synthetic based mud's have become increasingly more important.
In 2005-6, several deepwater locations will be drilled using non-aqueous based drilling fluids. Of key interest is the availability of paraffin base stock from Shell MDS (Malaysia Sdn Bhd.’s plant in Bintulu). Paraffin based systems are currently in use and found to be effective by other operators in the area. Because paraffins do not currently meet all US EPA laboratory test criteria (toxicity and biodegradability), there is a strong interest in collecting actual field data to assess the environmental fate of such discharges. Shell Malaysia is embarking on a unique field study program to assess the fate of the paraffin based mud's and cuttings in water depths ranging from 300-1,500 m and to compare the data to similar studies with internal olefin mud's.
Shell Global Solutions International B.V., with experience in SBM's and deepwater environmental monitoring, had designed an approach to answer the key questions. The primary local contractor on the project is Petronas Research and Scientific Services Sdn. Bhd. (PRSS). Metocean data from the study area is being used, in conjunction with a state of the art drill mud dispersion model to predict the 3-D accumulation of the cuttings and mud on the seafloor. Gas chromatographic techniques (GC-FID) will be used for identifying and quantifying the presence of paraffins in the marine sediments. Ecological risk methodologies are being used to predict potential benthic impacts. Each of four drilling locations will be sampled post drilling and one year later. This will provide important insight into the weathering rates of paraffins in sediments.
The study design, methods to be employed, and preliminary modeling and ecorisk evaluations are presented and discussed in the paper.
New API Practices for Isolating Potential Flow Zones During Drilling and Cementing Operations
Authors: Bannerman M. , Calvert J. , Griffin T. , Levine J. , McCarroll J. , Postler D. , Radford A. , Sweatman R. 
Published: January 2008

Abstract
This paper summarizes the progress by government and industry representatives of the API Work Group on Annular Flow Prevention and Remediation in studying the causes and prevention of deepwater shallow water flows (SWF) and annular flow incidents in other wells resulting in loss of well control linked to the well-cementing process. An overview is provided on two new API recommended practice publications (RP-65 Parts 1 and 2) that describe preventive and controlling measures for SWF in deepwater wells and for any flow zone in almost any type of well. This includes key well planning, drilling, and cementing practices designed to help ensure isolation of potential flow zones. The paper also mentions plans to prepare Part 3 of RP-65 on prevention and remediation of sustained annular casing pressure during production.
This paper introduces and promotes the use of best practices associated with prevention of annular flow incidents. It will also help inform the industry on pending regulations that may require the use of RP-65 in preparing Applications for Permits to Drill (APD) and in drilling and cementing operations in areas regulated by the MMS (Minerals Management Service) of the U.S. Department of the Interior.
Development and Implementation of a High Strength "Mild Sour Service" Casing Grade Steel for the Kristin HPHT Field
Authors: Nice P. I. , Øksenvåg S. , Eiane D. J. , Ueda M. , Loulergue D. 
Published: January 2008

Abstract
The Kristin Field is a high pressure high temperature gas condensate field located in the Haltenbanken area on the Norwegian Continental Shelf.
The well design and operation challenges during the drilling and completion phases, as well as the long term production phase, of the Kristin wells required the need for a "mild sour service" production casing grade capable of handling large differential pressures and high axial loads. To meet the requirements, the initial selection was a large OD, heavy weight C-110 grade casing. However, the overall casing weight, the annular flow area during cementing and the compression capabilities of the available connections called for a material grade with specified minimum yield strength of 125 ksi (862MPa). This grade would allow for a down scaling of the casing dimensions and the use of qualified premium connections suitable for the Kristin conditions.
The recent development of a 125ksi (862MPa) high strength low alloy (HSLA) steel casing grade for "mild sour service" applications has permitted this specific design requirement to the Kristin production casing OD to be met.
This steels metallurgical design included reducing the dislocation density and controlling carbide morphology to enhance the sulphide stress cracking (SSC) resistance. It was found that vanadium containing steels, produced lower dislocation densities than vanadium-free steels, at same strength levels, because vanadium containing steels were tempered at a higher temperature than vanadium-free steels. The higher temperature tempering enhanced the SSC resistance, as a result of the uniform and spheroidized M3C distribution and decrease in dislocation density. A decrease in chromium (Cr) content, which had little effect on temper softening resistance, was beneficial for preventing M23C6 (M=Fe, Cr, Mo) formation. The 0.5Cr-0.7Mo-0.1V steel without M23C6 carbide had higher SSC resistance than the 1Cr-0.7Mo-0.1V steel.
This paper will describe this specific well design challenge provided by the Kristin field production wells and how this was resolved by the introduction of this new HSLA steel grade. Then explain the detailed metallurgical design development needed to provide improved SSC resistance that was required for the "mild" sour service conditions found in the Kristin reservoir fluids.
Unlocking the Value in West Sak Heavy Oil
Authors: Targac G. W. , Redman R. S. , Davis E. R. , Rennie S. B. , McKeever S. O. , Chambers B. C. 
Published: January 2008

Abstract
West Sak is a heavy oil accumulation within the Kuparuk River Unit on the North Slope of Alaska. It is a Cretaceous, shallow marine sandstone. It contains 7–9 billion barrels of oil in place with an oil gravity that ranges from 10–22 degrees API. Initial oil production began in 1997 at approximately 3,000 BOPD and has increased to over 16,000 BOPD in March 2005. Development plans are in place to achieve a rate of over 40,000 BOPD by 2007.
This paper describes the evolving development plan for the West Sak field, with emphasis on the technical advances that have resulted in large-scale commercial development. Early West Sak development consisted of stimulated vertical wells on a 40-acre waterflood pattern with typical production rates of 150-250 BOPD. Utilizing the evolution in horizontal and multi-lateral drilling technology, the development plan has progressed to extended reach multi-lateral injectors and producers with horizontal and undulating slotted liner completions is excess of 8000 feet per lateral. Peak rates of over 5000 BOPD and sustained rates of over 1500 BOPD have been achieved. With the higher reservoir throughput rates, the distance between wells has increased, reducing well count and improving the development cost per barrel.
Significant changes have also been made to the completion design and production strategy. These include changing from sand exclusion to sand management, adding intervention capabilities with multi-lateral completion equipment, optimizing the drill-in-fluid, and adding a backup gas lift system to the standard electrical submersible pump (ESP) completions.
Finally, the enhanced recovery process has evolved from waterflood to a viscosity reducing water-alternating-gas (VRWAG) process, improving expected recovery by 2-3 percent of OOIP.
Application of new technology and optimized development decisions have reduced development cost by approximately 25% in terms of $/BOE and unlocked value in a major resource.
Diffusion and Dispersion in the Simulation of Vapex Process
Authors: Das S. 
Published: January 2008

Abstract
The solvent based recovery process "Vapex" has a great potential for the recovery of heavy oil and bitumen resources, due to the low energy intensity and reduced GHG emission associated with the process. The process has been extensively investigated in the laboratory models and through numerical simulation studies. This has indicated the technical viability of the process as an alternative to thermal recovery processes, viz. SAGD. In the last few years several proprietary pilot has been developed to establish the commercial viability of this concept.
The most important uncertainty about this process is the rate of mixing of solvent molecules with high viscosity hydrocarbons. Due to low molecular diffusivity the theoretical predictions of extraction rates are significantly lower than the SAGD process. However, the results of physical model experimental carried out by this author showed a considerably higher mass transfer rate at the solvent bitumen interface. The process, whether in the laboratory model or in the reservoir porous media, takes place in a microscopic level. An experimental evidence of this phenomenon will be presented in the paper.
Transferring this microscopic phenomenon into a macroscopic simulation model presents a serious challenge. Artificially higher diffusion or dispersion coefficients are used to match the experimental data. Even with that both the production rate and the solvent saturation profile can not be matched simultaneously. For example the higher dispersion coefficient results in deep penetration of the solvent, resulting in a diffusion zone, thicker than the experimentally determined value. Lower dispersion coefficient results in a lower production rate. Some of these simulation results are presented in this paper. A recent development in the simulation model, Dynamic Grid Refinement, improves the simulation match by allowing the use of smaller grid blocks at the diffusion boundary layer.
Novel Reservoir-Simulation Methods Enable Direct Optimization of Expansion Decisions in Giant Heavy-Oil Field
Authors: Osterloh W. T. , Menard W. P. 
Published: January 2008

Abstract
Giant, geologically complex heavy oil fields can take decades to develop, so development decisions made early in the life of the field can have long-range implications. Decision and risk analysis (D&RA) is often used to make decisions that will maximize risk-adjusted economic benefit. Unfortunately in large heavy oil fields, D&RA can be very challenging due to the large number of variables and the endless number of development and expansion scenarios to analyze. The time needed to complete a D&RA can become prohibitive when full-field reservoir simulation is the main tool for forecasting primary production and well count, with one simulation taking many hours or days to complete.
This paper describes two new simulation tools developed to overcome these challenges: 1) a method for populating a model with hundreds-to-thousands of horizontal wells, and 2) a method to quickly and directly optimize expansion decisions.
A semi-automated spreadsheet-and-simulation method was developed to quickly place and select hundreds-to-thousands of hypothetical/future horizontal wells in a multi-million grid-block model. Because the method automatically accounted for all model static properties and their effects on dynamic production response, the hypothetical wells had productivity characteristics very similar to actual drilled wells placed in the model.
A multi-variant non-linear interpolation method was developed that enabled full-field forecasts – for any combination of acreage allocation, well count, drilling order, and expansion rate constraint – to be calculated in less than 5 seconds, compared to about 20 hours for traditional simulation. Extensive validation work showed that well count and production curves from the spreadsheet virtually overlaid those obtained using traditional simulation of the particular expansion scenario. Such close agreement was possible because the basis of the spreadsheet forecast was utilization of traditional simulation forecasts from a handful of relevant cases.
A key breakthrough beyond just fast forecasting was the coupling of the following three components inside the same spreadsheet: the fast forecasting method, calculation of an economic indicator/objective function (NPV), and commercial optimization tools. This linkage made possible, perhaps for the first time (at least at this scale), realization of direct optimization of any development scenario in a matter of minutes to a few hours, depending on the number of variables being optimized.