bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Hydraulic Effect of Tool-Joint on Annular Pressure Loss
Authors: Enfis Majed , Ahmed Ramadan , Saasen Arild 
Published: September 2011

For a successful drilling operation, downhole pressure or equivalent circulating density (ECD) control is very critical. Conventional drilling techniques require maintaining the bottomhole pressure between pore and fracture pressures. Specially, in deepwater wells, the margin between these pressures is very narrow. As a result, the bottomhole pressure and ECD must be predicted accurately and maintained within the narrow margin to avoid kicks and circulation losses. In the past years, a number of wellbore hydraulic studies have been conducted to predict the annular pressure losses. The effects of drillpipe rotation speed, borehole geometry, and pipe eccentricity on annular pressure loss have been investigated earlier. However, very limited studies have been carried to investigate the effect of tool-joint on the hydraulics. The presence of a tool-joint changes the annulus geometry between the drillpipe and casing/hole resulting in strong turbulence and fluid acceleration that generate additional viscous dissipation and pressure losses.
This article presents the results of theoretical and experimental studies conducted to examine the hydraulic effects of rotating and non-rotating tool-joints. Two different tool-joint geometries were considered in the investigation. Tests were performed with water based fluids that have different rheological properties under both laminar and turbulent flow conditions. Results show substantial increase in pressure loss gradient around the tool-joints. The increase in pressure loss depends on fluid properties and flow geometries. The rotation of the pipe tends to slightly affect the pressure loss. Using dimensional analysis in conjunction with theoretical methods, new theoretical and semi-empirical models have been developed to account for the contribution of tool-joints to the total annular pressure loss. Models predictions show good agreement with previously reported laboratory experiments. The new models are very useful to predict downhole pressure in deepwater and extended reach wells where accuracy in hydraulic calculations is very important.
Stay in the "Box": A Consistent Method for Configuring (Loading) Reciprocating Compressors to Optimize Performance
Authors: Harms Larry K. , Garza Manuel A. 
Published: September 2011

Abstract
Reciprocating compressors are a vital element in the production of onshore natural gas and oil but there is no accepted method for configuring compressors consistently to optimize performance. Most configurations (setting the compressor’s allowable operating range, load and capacity) are done based on an undocumented method unique to the individual doing the configuration, using inconsistent data and parameters with multiple and varying safety factors. This reduces the compressor’s effectiveness and in the end limits production. A structured method that relies on constructing and staying in an operating diagram "box" using set parameters and data has been developed to enhance compression effectiveness. This method helps achieve a common understanding among operations, maintenance and engineering personnel and consistently configures reciprocating compressors for optimized performance, increased reliability and safe operation. The method is explained and the results of implementing the method in a major onshore gas field are discussed.
Managed Pressure Drilling Enables Drilling Beyond the Conventional Limit on an HP/HT Deepwater Well
Authors: Kernche F. , Hannegan D. , Sammat E. , Arnone M. 
Published: September 2011

Abstract
This paper describes the successful application of Managed Pressure Drilling on a HPHT well drilled offshore. Wells in located in the field where this particular paper was focused and other offset wells in the area had faced many problems including inadequate mud management due to depleted or over pressured zones, influxes, mud losses and differential sticking. This well was a High Pressure and High Temperature (HPHT) well drilled in the area using the MFCS MPD system, closed loop method of accurately monitoring and controlling flow and pressure which can significantly reduce NPT.
Extensive engineering, training and development of procedures were carried out prior to spud. MPD was utilized to drill two hole sections. Specific MPD techniques were developed to handle the drilling operations. The resulting benefits associated with MPD led to improvements in drilling performance, and eliminated many of the traditional problems faced on other HPHT wells in the area. MPD has now become an integral part of the well operating philosophy and has established new standards for drilling wells of this type.
The MPD system was used from the start drilling of the 12 ¼" section to end of drilling 8 ½" section. One of the main benefits of using the MPD system was the ability to control the pressure dynamically when drilling through abnormally pressure layers by manipulation of surface back pressure instead of mud weight changes to maintain drilling progress. This facilitates rapid and safe rising of bottomhole pressure to control influxes and their subsequent bleed down. The utilization of this system on this well helped drilling to target depth while effectively handling influxes with significant time saving. The system was used for the first time to facilitate fishing operation by using a lighter mud weigh and manipulate the proper surface back pressure. The planning, development and execution phases of the MPD project are detailed in this technical paper.
Optimizing Horizontal Stimulation Design Utilizing Reservoir Characterization from Decline Curve Analysis
Authors: Gonzales Veronica M. , Callard Jeff 
Published: September 2011

Abstract
Existing flow models aid in the identification of key variables, such as original hydrocarbons in place and the productivity index, from examining various flow regimes from production decline data. In addition, specialized plots and well configuration information can infer additional reservoir characterization such as system permeability and fracture half length. Reservoir system permeability is crucial in designing multi-stage completions in order to prevent premature stage competition. Fracture half length determination provides a basis for designing lateral spacing.
Determination of the duration of the linear flow period toggles performance prediction thus providing a performance model that can be coupled with economics to optimize number of stages in horizontal wells. This system permeability also allows fracture half length to be calculated during the linear flow period from the production data.
Studies within various reservoirs have provided a methodology for analyzing and establishing infinite acting versus boundary dominated flow patterns including single phase gas, dissolved gas drive and retrograde condensate reservoirs.
The application of this study is to demonstrate the work flow in characterizing reservoir and fracture parameters and utilize this information to optimize economic recovery.
Interwell Water Tracer Pilots in North Kuwait Fields, A Valuable Opportunity to Understand Fluid Movement within a Waterflooded Reservoir
Authors: Al-Ajmi Moudi , Pathak Ashok , Al-Otaibi Basel , Al-Mufarej Mishal , Ashkanani Fatma , Abdullah Waleed , El-Doushy Ahmad , Al-Hamer Mohamad , Al-Anzi Ealian 
Published: September 2011

Abstract
Front-tracking and monitoring of pattern water-flooding are crucial reservoir management activities in the Mauddud (MA) carbonate reservoir. This depletion drive reservoir has been on water flooding since 2000. To help understand the complex water movement that has been observed following implementation of the water floods, it is essential that water tracers be employed in MA injection wells. The use of tracer technology is becoming increasingly important to the petroleum industry and it has proven to be an efficient tool to investigate reservoir flow performance and reservoir properties that are controlling fluid displacement processes. Inter-well tracer has proven to be successful in identifying direct communication between the injection and production wells, flow patterns within the reservoir, thief zones, swept pore volume, reservoir layering, and flood performance. Tracer studies have also been used to complement the information provided by other reservoir characterization methods such as pulse and interference testing.
Water tracers were employed in MA since 2007 at a pilot level, which is gradually expanding to full-scale implementation. Monitoring tracer breakthough information have provided invaluable information concerning the influence of faulting and stratigraphy on fluid migration within the reservoir which has been used to guide calibration/updating MA model and planning more tracer projects. The tracer data have been used to reduce the uncertainty attributed to well-to-well communications, and vertical and horizontal flow barriers.
The study presented in this paper includes two injection wells which have been on waterflood since 2000. Different water tracers were injected in this field since 2007. Produced water samples were collected for tracer detection. This paper includes discussions on the implementation of tracers in a carbonate reservoir presenting detailed analysis and interpretation of the results.
On Application of Non-Cubic EoS to Compositional Reservoir Simulation
Authors: Yan Wei , Michael L. Michelsen , Erling H. Stenby 
Published: September 2011

Abstract
Compositional reservoir simulation uses almost exclusively cubic equations of state (EoS) such as the SRK EoS and the PR EoS. This is in contrast with process simulation in the downstream industry where more recent and advanced thermodynamic models are quickly adopted. Many of these models are non-cubic EoS, such as the PC-SAFT EoS. A major reason for the use of the conventional cubic EoS in reservoir simulation is the concern over computation time. Flash computation is the most time consuming part in compositional reservoir simulation, and the extra complexity of the non-cubic EoS may significantly increase the time consumption. In addition to this, the non-cubic EoS also needs a C7+ characterization. The main advantage of the non-cubic EoS is that it provides for a more accurate descrition of fluid properties, and it is therefore of interest to investigate the computational aspects of using such models.
In this work we test the feasibility of applying a non-cubic EoS to reservoir simulation, using a slimtube simulator to simulate multicomponent gas injection using both the traditional SRK EoS and the non-cubic PC-SAFT EoS. Computation times for both models were compared. In addition, C7+ characterization for PC-SAFT and the performance of PC-SAFT in PVT modeling are also addressed.
Analysis of Field Responses to Low-Salinity Waterflooding in Secondary and Tertiary Mode in Syria
Authors: Mahani H. , Sorop T. G. , Ligthelm D. , Brooks A. D. , Vledder P. , Mozahem F. , Ali Y. 
Published: September 2011

Abstract
Low-salinity water injection is an emerging IOR/EOR technique, applicable to mixed-to-oil-wet sandstone reservoirs. This paper describes the field response for two large fields: Omar (secondary flood) and Sijan (tertiary flood). The data were analyzed using analytical and numerical modelling tools. This included evaluation of scaling numbers, mixing and dispersion and calibration. Insight was obtained on relevant drive mechanisms.
The responses to low-salinity flooding differ for the two fields: In Omar, a dual-step water-cut development was observed, which is characteristic for a change in wetting state. Our interpretation is that in this field, viscous forces provide the dominant drive mechanism, which is favorable to low-salinity flooding. We were able to history match the low-salinity response using a simple conceptual model.In Sijan, the low-salinity flood appears to be still immature and breakthrough of low-salinity water has not (yet) been observed. The reasons for the muted response thus far are explored, including a rather strong buoyancy effect caused by the higher permeability of the block, and the significant effect of injectant mixing with the highly saline aquifer.
A proposal is made for a workflow on how to apply this analysis to future low-salinity flooding implementation in field cases.
Practical Aspects of Gas Material Balance: Theory and Application
Authors: Diamond Phil , Ovens Jonathan 
Published: September 2011

Abstract
Gas material balance is often considered one of the more elementary areas of Reservoir Engineering. However, the simplicity of the straight line p/Z plot is often masked by many geological realities: partially sealing faults, aquifer influx, heterogeneity and low permeability. The purpose of this paper is to present a more realistic but still practical theory of gas material balance.
The paper begins by reviewing the underlying theory behind gas material balance and shows how an average reservoir pressure can be calculated that accounts for flux between reservoir compartments and by using this average reservoir pressure, water influx volumes can be estimated in compartmentalised reservoirs. The technique is applied to three real field cases; in the first case water influx was suspected but using this analysis it was possible to show, convincingly, that there was no water influx and previous deviations from a straight line p/Z trend were due to partially sealing faults. In the second case, the field clearly did suffer from aquifer influx and we show how this technique was used to estimate the invaded volumes and the material balance analysis was validated by core flood results.
Finally, we show a case where the material balance technique has been linked to an uncertainty analysis. For each GIIP estimate, a corresponding water influx volume was calculated, which in turn was converted to an equivalent displacement of the gas-water contact (GWC) depth. We show how the "most likely" GIIP and water influx estimates for the field were validated by production and log data from two wells within the field.
CO2 EOR Production Properties of Chalk
Authors: Olsen D. 
Published: September 2011

Abstract
The production properties of chalk from the Tor and Ekofisk Formations of a Danish North Sea oil reservoir were compared in two core flooding experiments at the conditions of the reservoir. Both experiments started with a water-flooding, and then continued with a CO2-flooding.
The Tor core sample was saturated with live oil to So=85.0 %, while the Ekofisk sample was saturated to So=63.7 %, the difference reflecting a difference in capillary pressure. The remainder of the pore space contained formation water. The water-flooding resulted in Sorw=25.3 % for the Tor chalk, and Sorw=37.7 % for the Ekofisk chalk. The difference in Sorw reflects different production properties during water-flooding of the Tor chalk and the Ekofisk chalk. After changing the flooding agent to CO2, the oil production resumed in both experiments, and resulted in SorCO2=5.8 % for the Tor chalk and SorCO2=4.6 % for the Ekofisk chalk. The Tor chalk produced 70.2 %OOIP during the water-flooding and 23.0 %OOIP during the CO2-flooding. In contrast, the
Ekofisk chalk produced 40.8 % OOIP during the water-flooding and 52.1 % OOIP during the CO2-flooding.
The inferior production properties during water-flooding for the Ekofisk chalk did not result in similar poor production properties during the CO2-flooding. The Tor chalk and the Ekofisk chalk showed production profiles that were very similar in the later part of the CO2-flooding, but differed in the early part, where the Tor chalk produced water, while the Ekofisk chalk produced oil. It is concluded that the Tor chalk and the Ekofisk chalk had different production properties in the water-flooding, but similar production properties in the CO2-flooding. Because the water-flooding left much more oil in the Ekofisk chalk, the CO2-flooding could recover a much larger oil volume from this rock.
Neither the Tor sample nor the Ekofisk sample showed evidence of dissolution after the experiments. Both samples remained within the elastic regime all through the experiments.
A significant potential for CO2 EOR may be present in Ekofisk chalk that is non-economic for water-flooding.
Experimental and Numerical Evaluation of Carbonated Water Injection (CWI) for Improved Oil Recovery and CO2 Storage
Authors: Kechut Nor Idah , Sohrabi Mehran , Jamiolahmady Mahmoud 
Published: September 2011

Abstract
One of the well-known problems in CO2 enhanced oil recovery (EOR) processes is the poor sweep efficiency due to the high viscosity contrast between CO2 and the reservoir resident fluids (oil and brine). CO2-augmented waterflooding or carbonated water injection (CWI) could lessen this problem. As CO2 is dissolved in and transported by the flood water, CO2 is more evenly distributed within the reservoir thus improves the sweep efficiency. This is beneficial to watered-out oil reservoirs where high water saturations could adversely affect the performance of the conventional CO2 injections. CWI also provides a very safe method for storing large quantities of CO2 as a dissolved phase in oil reservoirs.
This paper presents the results of our experimental and numerical investigations on the oil recovery and CO2 storage benefits of CWI in secondary and tertiary recovery modes through a series of coreflood experiments and detailed compositional simulation. The experiments were performed in a water-wet Clashach core with decane as well as restored North Sea reservoir core with stock tank crude oil and seawater at reservoir conditions. The experimental results demonstrate that CWI in both secondary and tertiary recovery modes can improve the oil recovery above the plain waterflooding. 45-51% of the injected CO2 was stored in the core at the end of the coreflood tests indicating the high potential of CWI not only for EOR but also as a CO2 storage injection strategy. Results of the corefloods were used to assess the capabilities and limitations of a commercial compositional flow simulator in modelling the CWI process. The simulation results show that diffusion should be taken into account to properly model the CWI process at the core scale. Using the commercially available reservoir simulators with the instantaneous equilibrium and complete mixing assumptions would lead to inaccurate evaluation of CWI process at this scale of interest.
Compensated Neutron-Gamma Density for Formation Evaluation, Continuing Field Tests Demonstrate Improvements and New Features
Authors: Reichel Nicole J. , Prabawa Hendrayadi , Mpanzu Antonio , Crowe John 
Published: September 2011

Abstract
Compensated neutron-gamma density (NGD) is a nuclear density measurement that can be made without a chemical gamma ray source. The measurement uses fast neutrons from an electronic pulsed neutron generator (PNG). These fast neutrons penetrate the formation and collide with and excite atomic nuclei. The nuclei rapidly return to their original energy state and emit gamma rays, some of which are scattered back to the detectors. The count rate of detected gamma rays, compensated for fast neutron transport effects, depends on formation electron density.
This new measurement is desirable where operating with a chemical source is prohibited or the risk of loosing the drill string in hole is high. The NGD measurement was first deployed on logging-while-drilling (LWD) equipment to minimize the impact of stuck-pipe events and to provide a density measurement with greater depth of investigation into the formation. The first implementation of the measurement used a ruggedized PNG as a source and a single detector, but the single detector configuration rendered the measurement sensitive to standoff. A caliper input was required to correct this effect, but introduced additional uncertainty. The measurement evolved to a standoff-compensated density using two detectors at different spacings from the PNG. The two detector responses are processed by means of a spine-and-ribs algorithm to correct for borehole effects, much like traditional cesium-based density measurements. This compensated NGD measurement provides standoff- compensated formation bulk density for formation evaluation, without using a chemical source.
The compensated NGD algorithm has been tested on various field datasets. The results are compared against an earlier uncompensated NGD algorithm and traditional gamma-gamma density (GGD) measurements. This paper provides an overview of the current compensated algorithm's advantages and highlights limitations that are currently being addressed through ongoing development.
A Sensitivity Study on CO2 Storage in Saline Aquifers
Authors: Pickup G. E. , Jin M. , Olden P. , Mackay E. J. , Sohrabi M. 
Published: September 2011

Abstract
It is recognised that saline aquifers have the potential to store large quantities of anthropogenic CO2. However, there is much uncertainty in aquifer properties which needs to be evaluated to ensure the safety of CO2 storage.
In the CASSEM Project (CO2 Aquifer Storage Site Evaluation and Monitoring), we have studied CO2 storage in two hypothetical near-shore UK sites. The work was undertaken in three phases (or levels), starting with existing data and simple models and moving on to more complex models as more data became available. The sites had contrasting structures: Site A consisted of simple layers, while Site B was more complex with anticlines and synclines.
Here we focus on the models in Levels 2 and 3. In Level 2, we had geological models, but no laboratory data, so typical values for properties such as relative permeabilities were assumed. In Level 3, the results of laboratory measurements were incorporated in simulations. We modified the Level 2 models in stages, changing one parameter at a time, so that we could evaluate its effect on pressure build-up at the wells, CO2 migration, dissolution and residual trapping. Thus the study formed a valuable sensitivity assessment.
In the models for both sites, the most significant difference between the Level 2 and Level 3 results was the use of the relative permeabilities which had been measured in the laboratory. In the Site B model, where there was more uncertainty in petrophysical properties, a reassessment of the absolute permeability, which led to lowering the average value by a factor of four, also had a large effect. We also assessed multiple realisations of the geostatistical model, and found these had little effect in Model A, but had a large effect for Model B due to pressure building up to the limit for rock failure in wells in low permeability regions.