bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Method for Forecasting Dynamic Reserve of Fractured Gas Well in Low-permeability and Tight Gas Reservoir
Authors: Ruilan Luo , Qun Lei , Yongxin Han , Jinde Feng , Chunhong Ma 
Published: July 2010

Abstract
Influenced by special geologic condition and stimulation, the production performance of low permeability and tight fractured gas well is obviously different from that of conventional gas well, such as longer unstable flow time, gas production with unit change in casing pressure, dynamic reserve and drainage area varying with production time, etc. So it is difficult to calculate reserve and drainage area accurately at early development stage. For these reasons, they bring great technical and economic challenges to the development of low permeability and tight gas reservoirs.
Properly recognizing the dynamic performance of fractured tight gas well and combined with modern gas production analysis technology, a new prediction chart of estimated reserve is established. This calculation utilized extended production data from several typical gas wells in Sulige gas field. Using early stage production data, the preditoin chart can provide estimations of gas reserve and drainage area of individual wells. Other parameters such as productivity scale, well pattern and spacing can also be included. This methodology can make prediction effectively with incremental production time. It is an excellent predictive guide to launch a development plan of the gas field.
Multi-Field Asset Integrated Optimization Benchmark
Authors: Rahmawati Silvya Dewi , Whitson Curtis Hays , Foss Bjarne , Kuntadi Arif 
Published: July 2010

Abstract
Integrated modeling of multi-field assets, from subsurface to market, is challenging due to the complexity of the problem. This paper is an extension of the SPE 121252, model based integration and optimization gas cycling benchmark [Juell, et al., 2009], extending two gas-condensate fields to two full-field multi-well models. Additionally, a full-field model is added to the Juell benchmark, introducing an oil field undergoing miscible WAG injection, where most data are taken from the SPE 5 Reservoir Simulation Comparative Project. All reservoir models are compositional, but using different EOS representations. A base case scenario is defined with fixed numbers and locations of producers and injectors.
A common field-wide surface processing facility is modeled with emphasis on water handling, NGL extraction, sales-gas spec, and gas reinjection. The surface process model interacts with the three reservoir models through two main mechanisms – (1) water- and gas-handling constraints, and (2) distribution of available produced gas for reinjection into the three reservoirs.
The field asset model provides long-term production forecasts of gas, oil, and NGL revenue. Cost functions are introduced for all major control variables (number of wells, surface facility selection and operating conditions, injection gas composition). Net present value is used as the target objective function.
This paper will evaluate optimal production strategies for the base case benchmark problem, using several key control variables and field operational constraints. Optimization performance will be tested with a few solver algorithms. The benchmark will be provided to the industry through application data files, network infrastructure, and results from our integrated optimization model.
Fluid Delumping Applied to the Goliat field: A Black-oil Model Coupled with a Process Design
Authors: Vignati Emanuele , Bonotto William , Cominelli Alberto , Stano Elena , Le Maitre Claire 
Published: July 2010

Abstract
It is a common practice to use a limited number of components to describe hydrocarbon fluids in reservoir simulation, even though process engineering needs a richer set of components to model the top-side separation process. This requires delumping of the well streams from reservoir models to meet the detailed description needed by the process engineers. We have tackled this problem on the reservoir model of the Goliat field, located in the south-western part of Barents Sea. Economically producible hydrocarbons have been proven in the Realgrunnen and Kobbe formations. Production strategy consists of periferic water injection for pressure maintenance and gas injection in the gas cap for disposal purpose.
The development plan includes the distillation of intermediate components from the separated gas phase. This can not be easily modelled within a black-oil reservoir simulator, because the process efficiency depends on gas volumes and gas molar composition that change along with the depletion of the reservoir. A possible solution is to build a reservoir-process model to provide corrected production profiles, and the efficiency of the solution relies on accurate and robust method to delump the black-oil streams.
We modified a well-known delumping method to account for Goliat peculiarity. Detailed fluid composition is calculated at each well completion. Phase molar flow is characterized interpolating the composition measured in differential liberation test. Since the gas is expected to be partially produced from the gas cap, the original method has been modified to distinguish between dissolved and dry gas composition, following the latter in the simulation as a tracer carried by the gas phase.
The application of this delumping algorithm offers several advantages. First, this method is cost-effective because it can be implemented efficiently by post-processing black-oil well streams, avoiding a much more time-consuming compositional simulation. Secondly, it increases the accuracy of forecast profiles since it takes into account the variation of the produced fluid composition with time. Finally, it provides sale-gas composition forecast according to the surface process facilities.
Design, Execution, and Results of the Longest Multizone Cased-Hole Gravel-Pack Completion in Malaysia
Authors: Saebi Shahryar , Tyutikov Sergey , Machado Angel , Curteis Charles , Rivero Maria Elba , Khaled Mohd Zaidan , Habib Mohamed Said 
Published: July 2010

Abstract
This paper reviews the sand control practices used in an offshore Malaysia field, including execution of the longest single-trip multizone cased-hole gravel pack in Malaysia, the challenges faced, and the lessons learned.
PETRONAS is currently developing an offshore field in Malaysia with wells designed to obtain medium-to-high production rates and be completed as gas-lifted dual-string producers. The lower sandface completion design was to gravel pack the lower and middle zones on a single run and selectively produce through the long string. The upper zone was then to be gravel packed and produce through the short string. Because of the long perforated intervals and exceptionally long distance between the producing zones, as well as different pressure profiles of the layers, shunt tube technique was identified as being the best practical method to overcome the operational challenges. The target reservoir is a laminated and multilayer sandstone formation. The lower and middle zones were gravel packed simultaneously with gross-producing intervals to 950 ft (the shaly section between the zones up to 600 ft). The upper zone was gravel packed separately with a gross perforated interval length to 775 ft. Due to the different pressures in the multiple zones, loss and crossflow control was a design requirement.
The project imposed a number of challenges, including gravel packing extremely long intervals while aiming to achieve suitable perforation packing efficiency in unconsolidated and soft sandstone formations and also providing the possibility of selective production during the life of the wells. The proposed solution to overcome these concerns consisted of combining shunt tube technique with a three-way sub-concentric completion system.
Five wells using this design have successfully been completed in this project with sand-free production rates exceeding expectations.
The proposed solutions and the lessons learned in this project could change the sandface completion practices for multizone and long intervals in the offshore Malaysia fields. The techniques used in this project resulted in considerable rig-time savings, lower skin, and better productivity through improved perforation packing efficiency compare to the conventional methods.
Downhole Scale Control on Heidrun Field Using Scale Inhibitor Impregnated Gravel
Authors: Selle Olav Martin , Haavind Frode , Haukland Marit H. , Moen Arild , Hals Carl F. , Øien Kåre , Strachan Catherine , Clark Graham 
Published: July 2010

Abstract
Scale inhibitor impregnated gravel (SIIG) is a new technology for combined sand and scale control that features porous ceramic proppant particles that are impregnated with scale inhibitor chemistry. The particles have been designed to be suitable for gravel pack pumping operations and can be pumped as 100% scale inhibitor impregnated particles or mixed with conventional gravel. The scale inhibitor impregnation technology has been optimised to provide a steady, controlled release of scale inhibitor chemical on contact with produced water. The technology provides for the first time in the oil industry a method of placing large quantities of solid state scale inhibitor in gravel packs. In typical gravel packed deepwater completions, particularly, sub-sea wells, the technology offers considerable cost benefits for scale control when compared to scale inhibitor squeeze treatments and negates the need for pre-emptive squeeze treatments in anticipation of seawater breakthrough.
After qualification of the product through a comprehensive laboratory development programme a field trial has been performed on a Heidrun well. The well was a sidetrack from the mother well, and it was chosen for the field trial as the initial water breakthrough was predicted to contain around 20% sea water. The field trial demonstrated that placement of the scale inhibitor impregnated particles could be successfully performed. However, the loss of scale inhibitor to the gravel pack fluid was higher than anticipated since it took three weeks between gravel packing and startup of the well. Despite the high intial loss of scale inhibitor to the gravel pack fluid the release of inhibitor during production was as planned. Unfortunately it did not protect the well from scaling since the mixing of sea water and formation water probably took place in the near well area behind the gravel pack.
This paper will provide a detailed description of the laboratory development of SIIG technology and, in addition, will also present details of the first gravel pack deployment of this technology for combined sand/scale control in a Heidrun well.
Phase Behavior of Steam with Solvent Coinjection under Steam Assisted Gravity Drainage (SAGD) Process
Authors: Li Weiqiang , Mamora Daulat D. 
Published: July 2010

Abstract
A detailed investigation of the phase behavior inside the steam chamber is important to understand the drainage mechanism of solvent co-injection under steam assisted gravity drainage (SAGD) process. A 2D simulation study based on typical Athabasca reservoir properties with hexane (C6) as the coinjection solvent shows that a successful solvent co-injection design can take both advantages of solvent and steam.
Due to differences in the boiling points of solvent and steam, the phase behavior inside the steam chamber is not uniform and is not the same for different production stages. The gas solvent, liquid solvent, and water accumulated along the oil-steam interface work together to affect the oil viscosity in a complex relationship. Based on results of this study, we suggest some directions of future research to improve solvent coinjection performance.
Pseudo-Steady State Productivity Equations for a Multiple-Wells System in a Sector Fault Reservoir
Authors: Lu Jing , Ghedan Shawkat 
Published: July 2010

Abstract
Wells producing from their own individual drainage area is only true for reservoirs at their early development. However, in matured oil reservoirs it would be acceptable to imagine several wells producing from the same drainage domain. Each well, then, will have an effect on the pressure of other wells. The flowing bottomhole pressure of a well producing at a constant rate is a function of its own production as well as the production from surrounding wells. Currently, in the oil industry, productivity equations for single wells are erroneously used, as they do not consider the interference effects on flow rates of different wells in the same drainage domain.
This paper presents a pseudo-steady state productivity equation for a multiple-wells system in a homogeneous, anisotropic sector fault reservoir with impermeable boundaries. Assume sector angle Φ is equal to π/n, n is an integer bigger than 1, take fully penetrating vertical wells as uniform line sinks, and use symmetry principle, a simple, reasonably accurate productivity equation for a multiple-wells system is obtained by solving a square matrix of dimension 2nm, where m is the number of wells. The proposed equation relates the production rate vector to the pressure drawdown vector, is applicable to a multiple-wells system arbitrarily located in a closed sector fault reservoir. Convenient algorithms to calculate shape factors for sector fault reservoirs, equilateral triangle reservoirs and isosceles right triangular reservoirs are provided. The value of the shape factor from the proposed equation is very close to its corresponding value published in the literature.
The benefit of the analytical model can be emphasized when the reservoir data deviate from their idealistic representation. It is concluded that, the proposed equations provide a fast analytical tool to evaluate the performance of a multiple-wells system in a closed sector fault reservoir.
Study on Development Mechanism of Commingling Production in Low-permeability Gas Reservoirs
Authors: Guo Ping , Wang Juan , Liu Qi-guo , Zhang Mao-lin 
Published: July 2010

Abstract
Low-permeability, low-production, low-abundance are the major features of the low-permeable gas reservoir. Commingling production has been widely used as an important method to improve the producing ability of gas reservoirs, however, the dynamic analysis and technical countermeasures for the multi-commingled wells are still not enough.
Started from the multi-commingled filtration theory model, the pressure characteristics and the contribution rate of production of each layer, which are under the different multi-commingled well conditions such as reservoir properties differences, interlayer pressure difference and different damage degree, are studied in this paper. The results show that the contribution rate is fixed on formation coefficient before the pressure wave reaches the boundary; and after that, it is fixed on the storage ratio, it could be fixed on the formation coefficient, storage ratio and kickoff pressure gradient when considering the kickoff pressure gradient. Although there are significant differences in permeability between layers, the well test pressure curves have little difference.
Taking the Da-niudi gas field for example, the single layer production rate, recovery and total recovery are studied by numerical simulation at different permeability ratio in multi-commingled well. The results show that the different permeability ratio contrast (&lt;10) models can all be commingled. The total recovery of different models has little difference, when the formation pressure declines to the abandonment pressure. However, the smaller the permeability contrast is, the longer the stable production period of the well is, and the less the interlayer recovery difference is; on the contrary, the shorter the stable production period is, and the larger the interlayer recovery difference is.
All the reservoirs in the multi-commingled well had better to be put into operation at one time. In this way not only the operation to succeed the late fill-holes can be saved, but also overall commingled layer recovery could increase.
Reservoir Architecture Characterization: EOS-Based Downhole Fluid Analysis, Openhole Logs and Pressures Integration
Authors: Xian Cheng Gang , Zuo Julian Y. , Haddad Sammy , Berrim Ahmed 
Published: July 2010

Abstract
Reservoir hydrocarbon fluids complicated properties and phase behavior with associated physics often reflect the complexities of reservoir architecture. Hence, it is of great importance to determine fluid heterogeneities at the early exploration and appraisal stage. Conventionally, however, gathering information on fluid heterogeneities and phase behaviors is a challenging process that requires numerous fluid samples and associated laboratory analysis. Although pressure gradients are often used to evaluate in-situ fluid densities, contacts, or connectivity, this method may be misleading as fluid compositional changes and compartmentalization give distortions to the pressure gradient fitting. Nowadays, Downhole Fluid Analysis (DFA) measurements are being effectively used to reveal fluid heterogeneities by providing various reservoir fluid properties in real-time. In order to allow an objective assessment of reservoir architecture, it is needed to incorporate a rigorous mathematical approach in respect of all data available.
This work demonstrates with field data an effective and reliable methodology for evaluating fluid variations with depth through an equation-of-state (EOS) approach by interpreting DFA measurements integrated with other conventional data. Using an established method, the topmost DFA data in a column was delumped and characterized, and then an EOS model is established for the reservoir fluids. The EOS parameters can be tuned to match DFA measurements at different depths. The tuned EOS is applied to predict compositional and property gradients with depth. If the difference between the predictions and DFA data is significant, then potential vertical discontinuity between the top pay zone and current depth must be investigated. Case studies are presented to illustrate how this methodology is applied. This work demonstrates that the EOS based methodology of integrating DFA data with other openhole logs provides a powerful tool of characterizing reservoir architecture, which is invaluable for optimal reservoir management and development.
Comparisons of Various Algorithms for Gas-lift Optimization in a Coupled Surface Network and Reservoir Simulation
Authors: Samier Pierre 
Published: July 2010

AbstractGas lift is used for gas-liquid two phase producers to boost the production. Increasing gas liquid ratio GLR reduces the average fluid mixture density in the well connections and therefore reduces the hydrostatic pressure drop and hence reducing the bottomhole pressure resulting in a higher production rate or a longer individual well production period. This technique is also used for deep offshore fields injecting the gas at the toe of the FPSO risers located at the seafloor.But as the lift gas supply is increased further, friction pressure losses in the tubing or the riser become more important and the production rate peaks then starts to decrease. Also high gas flowrates may induce corrosion problems, and the total amount of available gas-lift is limited. Therefore an optimal gas-lift rate exists for a maximum production rate or more generally a maximum production profit.Various gas lift optimization algorithms have been proposed in literature for optimizing gas-lift to individual wells or within a group of wells, very few are suitable for long-term reservoir development studies with gas-lift injection within a network (FPSO riser toe for example).Commercial simulators such as Eclipse, VIP, Nexus, … provide internal optimization tool which are convenient for gas-lift at wells connections. Optimizing gas-lift within a network with additional gas rate inside flowlines or risers becomes much more complicated since the THP limits of all the other wells in the network are affected. Each time a lift gas increment is added or substracted, the whole network must be rebalanced with the appropriate lift gas rate in order to recomputed the change in the field oil production rate. The paper reviews some of the optimization methods available in commercial coupled surface network and reservoir simulators such as Resolve -Gap-Eclipse, Nexus, Avocet, …Several optimization algorithms linked to a surface facility model coupled to an open reservoir simulator prototype have been also applied (Ensemble based method, Steepest-Descent, Gauss-Newton, BFGS,..) and compared to previous commercial software solutions.Results of the comparisons are presented on a surface network model coupled to a reservoir simulator where the objective is to optimize the gas-lift allocations at riser toes.One of the test cases based on a modified SPE 9 comparative test is fully documented and allows the readers to compare results with their own optimization algorithm.
Design, Development and Testing of a Slimhole Rotary Steerable System
Authors: Jones S. , Sugiura J. , Das P. 
Published: July 2010

Abstract
The first commercially successful Rotary Steerable Systems (RSS) were introduced in the mid-1990's for 8 ½-in. and 12 ¼-in. sections on high-end drilling applications. As the systems have matured and day rates reduced, they have been adapted to drill all borehole sizes from surface to the target depth.
RSS are highly complex tools consisting of mechanical, hydraulic and electrical systems all functioning simultaneously. Because of their complexity, systems designed for slimhole applications (5 ¾-in. to 6 ¾-in. sections with 4 ¾-in. collars) have typically been challenged with poor reliability. As these slimhole systems have matured, reliability and durability have increased through continuous improvements in some of the most challenging drilling conditions.
This paper presents the design, development and testing phases of a new slimhole RSS. The design stage describes the use of existing experience from larger RSS and methodology to make the assembly adaptable to all drilling applications. The development and testing phases of the project will be described in detail from workshop and drilling facility testing to semi-commercial applications to evaluate performance.
The confidential drilling facility testing was used to evaluate and enhance directional performance and reliability with a wide range of formations, drill bits, bottom-hole assemblies (BHA) and parameters. The testing format was designed around current directional well profiles for 5 7/8-in. to 6 1/8-in. hole where RSS are typically deployed. Reliability improvement was established by gradually step changing drilling and directional parameters to maximum or beyond the design specification of the system.
The initial customer trial phase of the system in established RSS environments is used as a proving ground to further develop the product for superior performance in challenging drilling applications.