bluuebunny/crossref_metadata_2025_split huggingface dataset:
Deepwater Reservoir Modeling Using Sequence-Stratigraphic and Geomorphic Constraints
Authors: Pranter M. J. , Reza Z. A. , Weimer P. 
Published: December 2007

Abstract
In deepwater-reservoir modeling, it is important to properly represent the spatial distribution of architectural elements to account for pore-volume distribution and the connectivity of reservoir sand bodies. This is especially critical for rock and fluid-volume estimates, reservoir-performance predictions, and development-well planning.
This new integrated stochastic reservoir-modeling approach accounts for stratigraphic and geomorphic controls to generate the reservoir architecture. Information on stratal-package evolution and sediment provenance can be integrated into the reservoir-modeling process. A slope-area analytical approach is implemented to account for topographical constraints on channel and sheet-form reservoir architectures and their distribution. Inferred paleo-channel direction statistics (from outcrop and stratigraphic studies) and simulated high-frequency eustatic sea-level curves are also used to constrain the architectural-element statistics. Based on these geomorphic and sedimentological constraints, architectural elements (channels, lobes, sheets) are built into the model sequentially (in age order).
Integration of realistic geological and engineering attributes into numerical reservoir models is vital for optimal reservoir management. This approach is unique in that it is constrained more directly to geomorphic and sedimentological parameters than traditional object-based or surface-based techniques for stochastic deepwater reservoir modeling.
Insights into Deepwater Frac-Pack Completions Using Radioactive Tracers
Authors: Pourciau R. D. , Waltman R. 
Published: December 2007

Abstract
Frac packing has become the standard sand-control completion technique for many deepwater operators because of low completion failure rates[1] and excellent production performance.[2] These treatments are engineered to optimally place the stimulation fluids and proppants based on gravel- pack (GP) tool operational procedures and fracture model simulations.[3] Direct near-wellbore measurements from radioactive (RA) tracers can be used to help minimize both engineering and operational uncertainties of this process.
A comprehensive review of 30 Gulf of Mexico frac-pack completions within four deepwater fields has been completed, in which RA tracers have been used. These logs allowed initial assessment of the sand control and resulted in better frac-pack designs. The average perforation length of these 30 completions is 94- ft and the average deviation is 41°.Three of these wells have more than 200- ft of perforations and seven have over 60° of hole deviation.
Analysis of Long-Term Production Performance in Acid-Fractured Carbonate Wells
Authors: Rahim Z. , Ahmed M. 
Published: December 2007

Abstract
Gas condensate wells within the Khuff Carbonate formation in Saudi Arabia are typically acid fracture stimulated following drilling.Pressure transient tests conducted after stimulation indicate excellent fracture conductivity and reasonable lengths.After tie-in the wells experience some early production change, which stabilizes after three to five months. The producing bottomhole pressure of many such wells also reaches near or below the dew point pressure during this period.
This paper identifies some reasons of production and pressure behavior.Possible causes of early rate change followed by stabilization that include near well liquid drop-out, fracture conductivity deterioration with increased effective in-situ stresses, reservoir permeability loss also due to increased effective stresses and pressure drop, and non-Darcy flow were investigated.The paper presents the changing total skin with time and allocates it to each of the potential damage mechanisms.This was accomplished using a full geomechanics and reservoir simulation model, which treats multiphase flow effects and stress-dependent matrix permeability as well as fracture conductivity.By doing so, the production behavior was matched and the main controlling factors were identified.
The paper introduces a generalized skin factor equation combining all major variables controlling production, separate individual terms with respect to well rates, and identify the main mechanism impacting production behaviour.
Decline Curves from Deconvolution of Pressure and Flow-Rate Measurements for Production Optimization and Prediction
Authors: Kuchuk F. J. , Hollaender F. , Gok I. M. , Onur M. 
Published: December 2007

Abstract
In this work, we propose a methodology for monitoring well productivity index (PI), forecasting production, and estimating reserves using pressure and flow rate data. Within this context, we also provide a system identification technique by computing constant-pressure rate (deconvolved rate) behavior based on deconvolution of pressure and rate measurements. These measurements can be subsurface, surface, or a combination of both. As downhole permanent monitoring systems become more widely used, data quality, frequency, accuracy, and resolution will improve.
For system identification, deconvolved rate is compared with the exponential decline of the system under depletion as a base. Any deviation from the exponential decline may indicate nonlinearities about the system. With this step's input, a geologically based well/reservoir model is constructed for parameter estimation (e.g., reservoir size, pore volume, etc.) using pressure and/or flow-rate measurements. Any available pressure-transient-test data will also be considered.
The methodology proposed in this work can be integrated into data-acquisition softwares for permanent sensors, to provide a real-time monitoring/diagnosis tool for well performance and prediction. Furthermore, deconvolution results and estimated parameters can be verified continuously through a convolution of pressure and rate data, without interrupting production. It is, therefore, well suited for a single well or group of wells under extended testing, equipped with downhole gauges, and flowing through surface separation and metering systems. Wells completed with permanent downhole rate and pressure instrumentation are also ideal candidates for this type of analysis. Two field examples are presented to demonstrate the application of the methodology.
Impact of Formation Type on Cement Bond Logs
Authors: Vidick B. , Krummel K. , Kellingray D. S. 
Published: December 2007

Abstract
Frequently, poor cement logs are observed in low gamma ray formations (sand). Contrarily, very good bond is often noted across high gamma ray formations (shales). In some cases this has resulted in a squeeze decision where no injectivity can be obtained incurring significant costs and delayed oil. Most commonly the problem has been ascribed to an artifact of the logs, presence of mud cake, cement shrinkage and squeezing shales.
However after studying many such logs the first observation is the sharp contrast between the logs across shales and sands. This can occur over an interval of less than a meter. We have also noted that within the same interval in a low gamma ray formation, very good and poor bonds can coexist. It is also shown that the frequency of poor bonding across shale does show a dependence on depth. It was concluded that these observations imply that fluid influx could be partially responsible for the poor bonding and mud cake was not the sole explanation for the effect. This influx is different to conventional gas/fluid migration and is associated with fluid entry into the cement after the cement has reached a oint of being able to prevent migration. Deeper analysis and correlation with reservoir pressure support this hypothesis, explaining why the log is very good in some sand intervals and poor across others. It would also explain the sharp contrasts in the log, as it is postplacement related while all fluids in the annulus are under static conditions. The remaining contrasts could be explained by greater bulk shrinkage of the cement across shales than across sands and squeezing shales. The larger fluid loss would allow influx of oil from the sands during cement setting, contaminating the slurry and therefore inducing poor logs. The paper describes, supports, and explains those mechanisms in detail. The role played by the liner top packer is also considered.
A Method to Normalize Log Data by Calibration to Large-Scale Data Trends
Authors: Kane J. A. , Jennings J. W. 
Published: December 2007

Abstract
Wireline log data is subject to numerous potential errors due to the acquisition environment and assumptions made during acquisition.The literature sites log quality problems on the order of fifty percent of all well logs.The implication of this is that wireline log normalization is a critical step in obtaining meaningful log data for any reservoir characterization or modeling study.Often insufficient information is available to properly normalize logs using common or traditional methods.A new method is introduced in this paper that relies only on a sufficiently thick log interval to properly estimate the parameters needed for the normalization.Through the use of first vertical averaging of data by well to minimize localized reservoir variations, followed by areal averaging of multiple wells to estimate correction terms for tool calibration affects, a robust method of well log normalization is presented.An example using data from the Fullerton Clear Fork Field is presented to illustrate the method.
Case History: Designing and Implementing Wireline Tractor Operations for Deepwater, Extended-Reach, Sand-Control Initial Completions and Interventions
Authors: Whiteley D. , Pourciau R. , Schwanitz B. 
Published: December 2007

Abstract
Wireline tractoring technology has set world and Gulf of Mexico records for several logging applications during the initial completion and intervention of two extended-reach, deepwater frac pack wells and one extended-reach, deepwater water-injection well. This paper reviews some of the challenges involved with conventional conveyance methods in extended-reach wells, describes the planning process for wireline tractoring operations, including prejob modeling, and summarizes the results of a project.The authors will also share the lessons learned and best practices implemented. Proper utilization of this technology has led to significant cost savings for the example project.
Foamed Conventional Lightweight Cement Slurry for Ultralow Density and Low ECDs Solves Lost-Circulation Problem Across Coal Formations: A Case History
Authors: Marriott T. , Griffith J. , Fyten G. , Mallett C. , Szutiak G. 
Published: December 2007

Abstract
Cementing gas wells in coalbed methane (CBM) formations can present a cement-circulation challenge because the coal formations tend to have low fracture gradients and break down under the hydrostatic pressure of the cement column. The use of conventional lightweight cement slurries and/or foam cement significantly increases the prospect of maintaining circulation throughout cement placement. However, wells with exceedingly low fracture gradients can suffer either partial or complete loss of circulation during cement placement even with lightweight slurries.
Both conventional lightweight cement slurries and foam cements have restrictions. Conventional lightweight cement systems use low-density materials (i.e. hollow spheres, gilsonite) and high water-to-cement ratios as a means of reducing the equivalent circulating density (ECD). The lightweight materials and high water requirements detract from the compressive strength of the cement, thereby limiting ultra-low densities while achieving adequate compressive strength. For foamed cement, the gas-to-slurry ratio should stay within a specific range to help ensure optimal cement properties; otherwise, the set cement could become permeable. This requirement has led to the hybridization of two systems to create an effective cementing solution. By combining the two systems, the best attributes of both can be captured. Starting with a lightweight cement system provides a low base-slurry density that allows the gas to be added to lower the density further while maintaining the compressive strength and foam stability.
This paper discusses an operator's challenge and the use of the above solution to cement wells in the Western Canada Sedimentary Basin (WCSB) across CBM formations.
Injection Strategies for Foam Generation in Homogeneous and Layered Porous Media
Authors: Li Q. , Rossen W. R. 
Published: December 2007

Abstract
Foam generation plays a crucial role in the use of foam for improved oil recovery, acid diversion and environmental remediation.This sandpack study extends previous work to layered media, the effect of surfactant concentration, and injection strategy, including alternating-slug (SAG) injection and pulsed injection rate and pressure.As in earlier studies, three foam states were observed: high-mobility coarse foam at low pressure gradient, low-mobility strong foam at high pressure gradient, and, in between, an intermediate state with nearly complete gas plugging.
With co-injection of gas and liquid in homogeneous sandpacks, foam generation occurred at lower pressure gradient and lower gas velocity at higher liquid injection rates, higher permeability, and higher surfactant concentration. Within the plugged state, the pressure gradients required for foam propagation were remarkably high (of order 10 psi/ft) given the high permeability of the packs.
In flow from lower- to higher-permeability layers, foam generation occurred at lower pressure gradient than expected in either medium by itself. However, a minimum threshold pressure gradient for foam generation was still observed when the permeability contrast was of order 5:1, contradicting theory for foam generation at a sharp permeability transition. Foam generation was observed at all pressure gradients when the permeability contrast was 20:1. With co-injection of gas and liquid into layered packs, the low-mobility zone near the transition in permeability spread downstream if pressure gradient was sufficient.
During gas injection in SAG processes, a low-mobility front traveled the length of homogeneous packs and then exited. In heterogeneous packs, SAG injection gave persistent low mobility near the transition in permeability. Gas mobility in SAG processes was from 10 to 100 times higher than with co-injection of gas and liquid.
Briefly raising injection pressure in steady co-injection helped trigger foam generation in layered media, but had no lasting effect in homogeneous packs.
Foam was not uniform within packs, especially in the plugged state. Therefore, properties averaged over the pack do not represent a homogeneous state. Care is needed in using such data to fit mechanistic models for foam behavior.
10K Dual Splitter Wellheads: First Worldwide Application on the Development of an Offshore Gas Field
Authors: Faget J. B. , Monneyron J. C. , Bourgeois A. , Payer N. , Cherng L. H. 
Published: December 2007

Abstract
Splitter wellheads allow to drill several wells from the same conductor pipe, which can bring significant benefits for conventional offshore developments by reducing the size and/or number of new wellhead platforms or by giving access to additional reserves from available platform slots. In April 2003, Cameron 9" dual Conductor Sharing Wellheads (CSW) were successfully installed by Total E&P Indonésie on Peciko offshore gas field development as the first worldwide application in a 30" conductor pipe of a 9" × 10,000 psi dual splitter wellhead and 4-1/2" × 6,500 psi Xmas-Tree. As a result, 120 MUSD could be saved on surface facilities costs by reducing the total number of wellhead platforms from 10 to 7 while targeting the same gas reserves. Drilling and completion costs remained in line with initial budgets, as the higher costs of long departure wells induced by the reduced number of platforms were balanced by the savings made with the slimmed down well architectures.
Wettability Alteration ro Intermediate Gas-Wetting in Gas-Condensate Reservoirs at High Temperatures
Authors: Fahes M. , Firoozabadi A. 
Published: December 2007

Abstract
Wettability of two types of sandstone cores, Berea (permeability of the order of 600 md), and a reservoir rock (permeability of the order of 10 md), is altered from liquid-wetting to intermediate gas-wetting at a high temperature of 140°C. Previous work on wettability alteration to intermediate gas-wetting has been limited to 90°C. In this work, chemicals previously used at 90°C for wettability alteration are found to be ineffective at 140°C. A new chemical is used which alters wettability at high temperatures. The results show that: (1) wettability could be permanently altered from liquid-wetting to intermediate gas-wetting at high reservoir temperatures, (2) wettability alteration has a substantial effect on increasing liquid mobility at reservoir conditions, and (3) wettability alteration does not have a measurable effect on the absolute permeability of the rock when a suitable chemical is used. We also found out that the reservoir rock, unlike Berea is not strongly water-wet in the gas-water-rock system.
Smart Operations: Cutting Costs by Use of Simple Completion Solutions on the South Pars Field, Offshore I.R. Iran
Authors: Teigen A. S. , Johannessen B. 
Published: December 2007

Abstract
In this paper we will discuss optimization of completion solution in the South Pars field. By means of simplified completion methods, completion and testing time has been cut by more than 50% compared to the time spent on previous completions in the South Pars field.
We will discuss why we decided to change the "standard South Pars completion solution" commonly used by all other operators in the same field, and we will present the operational results from the first fourteen wells.
Analyses of the Accuracy and Reliability of Magnetic Directional Surveys
Authors: Nyrnes E. , Torkildsen T. 
Published: December 2007

Abstract
Multi-station processing techniques can be used to improve the accuracy of wellbore directional surveys by removing the effects of systematic errors. The main intention of this paper is to provide improved understanding and documentation of such methods when applied to magnetic surveys. Basic properties of the method are discussed in detail. The combined use of statistical tests and multi-station estimation techniques are evaluated, together with the ability to improve the accuracy of wellbore positions. This is demonstrated for a wide range of surveying conditions.
Due to a number of reasons; poor geometry, low redundancy, high random noise levels, the presence of gross errors, and errors in the Earth's gravity and magnetic field references, it is often possible that there will be a misinterpretation of the estimation results. This may lead to reduced accuracy and quality of the surveys. Even under the best possible conditions it is demonstrated that the processing of multiple surveys does not necessarily improve accuracy, rather it impairs accuracy and produce unreliable results.
The study also shows the importance of having a sound understanding of the simultaneous effects of potential uncorrected systematic effects, in order to increase the chance of making correct conclusions.
A New Approach to Modeling Hydraulic Fractures in Unconsolidated Sands
Authors: Zhai Z. , Sharma M. M. 
Published: December 2007

Abstract
Field data show that fracturing in poorly-consolidated rocks is not adequately represented by traditional models for brittle, linear-elastic rocks. This is not unexpected since unconsolidated sands do not exhibit brittle- elastic behavior. In addition, sands have very low tensile and shear strengths.
A model is presented for the propagation of "fractures" in unconsolidated sands. The model departs radically from current models in that brittle fracture mechanics is not used. Instead the propagation of pore pressure is computed and the porosity and permeability of the sand is specified as a function of the effective stress. This results in the creation of an anisotropic zone of increased porosity and permeability along the plane of maximum in-situ stress (normal faulting stress regime) or at a certain angle to it (strike slip faulting regime). This region of enhanced porosity defines a "fracture" in unconsolidated sands. The physics of creation and propagation of this oriented, high permeability zone, is modeled for the first time.
It is shown that in-situ stress anisotropy and shear failure play a very important role in determining the dimensions of this fracture zone. In addition, the permeability anisotropy generated due to the stress anisotropy in the sand is the critical driving force behind the creation of the oriented "fracture".
During the hydraulic fracturing of an unconsolidated formation, a high permeability zone (channel or fracture) will form in response to the difference in situ horizontal stresses and the decrease in the net effective stress near wellbore. To correctly model the fluid distribution, the fluid flow behavior must be coupled to the mechanical behavior of the sands. Based on the coupled geo-mechanics and reservoir simulation (model, iterative-coupled 2-D finite difference software is developed to simulate the strain, stress change due to the injection. Based on the constitutive relationship of permeability and porosity, we modeled permeability and porosity as a function of effective stress.
Interpretation of Distributed Temperature Data During Injection Period in Horizontal Wells
Authors: Gao G. , Jalali Y. 
Published: December 2007

Abstract
This paper presents an analytical solution describing the variation of temperature along the length of a horizontal well, given an initial reservoir temperature and injection fluid temperature at the heel of the well. The solution can account for the variation of the heel temperature over time (e.g., decreasing heel temperature with injection time, which happens when a ‘cold’ fluid is injected into the wellbore, causing cooling along the well column, and decreasing heel temperature). The solution can also account for an arbitrary distribution of injection profile along the length of the well. This includes injection profile that is uniform, or is skewed towards the heel or the toe, or exhibits some discontinuity (e.g., leakoff into a high-permeability streak or fracture).
The analytical solution is obtained from a theoretical treatment accounting for mass transfer from the wellbore into the reservoir, and heat transfer from the reservoir into the wellbore. The treatment is 1-D linear in the wellbore and 1-D radial in the reservoir. The solution is valid for ‘early-time’, that is, the period during which fluid propagation (mass transfer) is not affected by bed boundaries. This may represent a period of days to weeks.
The solution can be used to generate the temperature profile in a horizontal injection well, for any assumed distribution of injection profile along the length of the well. The solution can also be used in the opposite sense, to infer the injection profile based on the observed temperature profile. Temperature profile in the wellbore can be measured with fiber optic Distributed Temperature Sensors (DTS).
This paper presents the theory, the analytical solution, synthetic examples and a case study from a horizontal water injection well in the Middle East.