bluuebunny/crossref_metadata_2025_split huggingface dataset:
Business Improvement by Integrated Concession Development
Authors: Beuthan H. C. , Shibani M. , Bremeier M. 
Published: December 2007

Abstract
Concession 97 in the Sirte basin of Libya is subdivided into three different exploitation areas (figure 1). The operator, Wintershall, developed discoveries in each area in 1988, 1990 and 1995 respectively. The producing reservoirs are in the challenging Sarir and Lidam horizons. The Sarir reservoirs are stratified sandstones with medium to very low permeability. The Lidam formation, consisting of a lower limestone and an upper dolomite, has limited net pay. While reservoir rock properties in both Sarir and Lidam reservoirs are of rather poor quality, the oil properties are very favourable.
Ongoing appraisal and the application of advanced exploration methods in recent years resulted in the discovery of additional fields and extensions. Substantial additional volumes have been appraised. However, primary recovery factors are expected to be relatively low.
Recent discoveries and the optimisation of the existing fields led to the completion of an integrated redevelopment of the entire concession. Three decentralized gas-oil separation plants were recently replaced by a central unit including gas utilization. A key challenge of such a scheme is the long distances, of up to 50 km, between oilfields and the separation plant. Trunk-lines with multiphase pumps are utilized to overcome the pressure losses and to allow reasonable backpressures at the wellheads.
Considerable savings in operational expenditures were achieved and the integrated concession development approach will enable the operator to apply different improved recovery strategies. The synergies gained from combining improved recovery methods are seen as a prerequisite for commercial application.
This paper aims to illustrate the integration of new field development and mature field re-development. The integration scheme enables the operator to implement improved recovery methods in difficult reservoirs which are not feasible on a stand-alone basis.
Upscaling of Foam Mobility Control to Three Dimensions
Authors: Li B. , Hirasaki G. J. , Miller C. A. 
Published: December 2007

Abstract
The applications of foam are 3-D on a field scale. However, most previous research focuses only on properties of foam in 1-D. Experiments were performed in 3-D, and the compositional reservoir simulator UTCHEM was modified to predict foam flow in 3-D.
The 3-D experiments demonstrated that, under similar experimental conditions, the mobility of foam in a 3-D tank is greater than that in a 1-D column. They also showed that foam greatly increases lateral gas distribution along the bottom of the tank and the average gas saturation for both homogeneous and heterogeneous packings with the effects being significantly larger in the latter case. The reservoir simulator UTCHEM was modified for foam flow. The foam simulation parameters were measured in 1-D sand columns and the simulator was modified to match the 1-D and 3-D experiments. The proposed model successfully history matched the homogeneous and heterogeneous 3-D sand tank experimental results for average gas saturation, gas injection rate, gas distribution and pressure profile along the tank diagonal 6 inches from the bottom.
The results of this study represent an advance in understanding of foam flow in 3-D. The simulator could be used to design a foam process in 3-D.
Oligocene Vicksburg Thin-Bed Production Optimization Derived From Oil-Based Mud Imaging: A Case Study
Authors: Fairhurst D. L. , Reynolds B. W. , Indriati S. , Morris M. D. , Hanson E. G. 
Published: December 2007

Abstract
The Oligocene Vicksburg formation in South Texas has been a prolific play for many years with targets of thick and stacked sand bodies. These thick sections have been primarily exploited and produced. Still existing are many previously considered uneconomical sequences. These marginal sections consist of highly laminated sand shale sequences along with disbursed clay in sand. Standard cutoffs from basic log evaluation work correctly for the disbursed clay sections. But the cutoffs are inadequate for the highly laminated sequences; many thin, high-quality sands have been overlooked. These sections can now be discerned using microresistivity measurements in oil-based mud systems and new high-resolution cutoffs can be employed.
A production prediction model is critical to enhance the chance of success. The model used here employs a petrophysically consistent high-resolution permeability estimate, fracture geometry prediction, and formation pressure. The methodology identified several sands as commercial that have been bypassed in offsets with the old cutoffs.
Over a two-year drilling program, data gathered from several field example wells were analyzed. These are presented here to illustrate how production data was utilized to continuously adjust and calibrate the high-resolution petrophysical model. The incremental revenue from the added pay exceeded the cost of this new methodology and enhanced the economic viability of the field.
This integrated process of measurement, analysis, prediction, evaluation, and model adjustment enables the operator in South Texas to make timely completion decisions as well as set-pipe decisions. This process is becoming a useful tool for further exploitation of the mature Oligocene Vicksburg formation of South Texas.
How to Apply a Blocking Gel System for Bullhead Selective Water Shutoff: from Laboratory to Field
Authors: Stavland A. , Andersen K. I. , Sandøy B. , Tjomsland T. , Mebratu A. A. 
Published: December 2007

Abstract
This paper describes a new method for water control by the use of bullhead injection. A water based gelant is emulsified in oil and injected into the formation. The emulsion is designed to separate into a water phase and an oil phase at static conditions in the formation. Upon reaction in the formation the water phase gels up while the oil phase remains mobile.
It has been found that the controlling parameter for disproportionate permeability reduction (DPR) is to control the fraction of gel occupying the porous media. The water fraction in the emulsion controls the reduction in relative oil and water permeabilities.
A program was undertaken to verify this DPR method in a field test, using a commercial blocking gel system. The first treatment was performed in well 30/3-A-16 T2 at the Statoil operated Veslefrikk field offshore Norway. Results show that water production was reduced by 30% after the pilot test, while maintaining the oil rate. As expected, total well productivity was reduced by more than 80%.
The treatment consisted of 124 m3 emulsion, bullheaded from surface. Step rate testing and ion water analysis were combined to study the relative change in flow contribution between the 6 perforated intervals.
The Effect of Displacement History on Three-Phase Capillary Pressure and Relative Permeability Derived from Triangular Pore Cross Sections with Contact-Angle Hysteresis
Authors: Helland J. O. , Skjœveland S. M. 
Published: December 2007

Abstract
We present a model of mixed-wet triangular tubes that calculates three-phase capillary pressure and relative permeability curves. Several fluid configurations may occur in triangular pore cross-sections, and capillary displacements may either occur as piston-like displacements of the fluids occupied in the bulk, or as piston-like displacements of the fluids in layers. To our knowledge, this latter type of displacement has not been analyzed before in mixed-wet pores. Using minimization of Helmholtz free energy, we derive accurate three-phase capillary entry pressures for such layer displacements, accounting for contact-angle hysteresis. Numerical examples are presented to illustrate how the entry pressures for the different possible displacements relate to each other during gas and water invasion into pores with a specific fluid configuration. It turns out that the entry pressures for related displacements are consistent. This implies that pores occupied by the same fluid in the bulk portion must have the same fluid configuration for a constant value of capillary pressure.
With this model we calculate three-phase capillary pressure and relative permeability, and explore how the saturation-dependencies of these quantities change according to saturation-reversal points. We simulate the sequence of processes primary drainage, imbibition and gas invasion, for different maximum capillary pressures Powmax er primary drainage. In the simulation results presented here, we find that the oil and gas relative permeability, and their saturation-dependencies, are sensitive to variations of Powmax, While the water relative permeability is less sensitive. Such effects are absent in cylindrical tubes. This is caused by the capillary entry pressures, which are strongly affected by hinging interfaces in the corners of angular pores when contact-angle hysteresis is assumed. Thus the choice of pore geometry is important if hysteretic capillary pressure and relative permeability relationships are simulated using network models. With respect to these findings, relative permeability and capillary pressure correlations should be formulated with parameters that strongly depend on saturation-reversal points such that different saturation-dependencies can be accounted for in subsequent invasion processes.
Dynamic FEA Models for Snubbing Buckling and Riserless Subsea Wireline Intervention
Authors: Newman K. R. , Overstreet C. C. , Beynet P. A. 
Published: December 2007

Abstract
A dynamic finite element analysis (FEA) calculation engine has been developed and is being used to solve specialized well intervention problems. This paper summarizes the theory used in this engine, and documents two of its applications. The first application is modeling the buckling behavior of pipe (or a bottom hole assembly) being snubbed through a packer. The second application is wireline being run from a boat to a subsea well to perform an intervention. The first step in this intervention is to jar the plug out of the tree.
Foam Mobility and Adsorption in Carbonate Core
Authors: Liu Y. , Grigg R. B. , Svec R. K. 
Published: December 2007

Abstract
The continued use of gas injection to improve oil recovery and the prospects for its increased use throughout the world provide impetus to improve sweep efficiency of injected gas. Work is being carried out to improve understanding and the economics of mobility control agents. This paper describes the use of foam to decrease the mobility of gas in coreflooding apparatus at reservoir conditions. Foam behavior and adsorption, two of the mechanisms required to model surfactant requirements, are studied in this project. This study uses a commercial surfactant, nitrogen gas, and reservoir conditions of 10.34 MPa (1500 psi) and 40°C (104°F), and Indiana limestone. Variables are surfactant concentration, flow rate and foam quality.
At a constant gas flow rate, gas mobility slightly decreases with increasing foam quality when below the critical foam quality (fg*) and increases with increasing foam quality above fg*. Increased surfactant concentration leads to the decrease of gas mobility. Comparing coinjected surfactant and gas (CSG) with coinjected water and gas (CWG) shows that the mobility of CSG is an order of magnitude lower than that of CWG. Also, it took more time for CSG to reach steady state compared to CWG, even with a surfactant pad conditioning the core before surfactant and gas were coinjected.
Development of a Correlation Between Performance of CO2 Flooding and the Past Performance of Waterflooding in Weyburn Oil Field
Authors: Asghari K. , Dong M. , Shire J. , Coleridge T. , Nagrampa J. , Grassick J. 
Published: December 2007

Abstract
Weyburn oil field, located in southeast Saskatchewan, is the location of one of the largest CO2 flooding projects in the world since September 2000.
In this paper, data of the past performance of waterflooding in the Weyburn field was used to develop empirical correlations to predict the performance of CO2 flooding. Two different correlations were developed based on CO2 injection schemes in Weyburn. The first correlation is based on a WAG process through vertical wells, and the second correlation is based on the cases in which CO2 is injected through horizontal wells and water is injected separately through vertical wells. As the first step, production data from 1958 to 2004 were collected and analyzed. Oil production rates for both waterflooding and CO2 flooding periods, water injection rates, and CO2 injection rates were used in developing the correlations. The empirical model for injecting CO2 and water through vertical wells was verified using the Kinder Morgan CO2 Scoping Model and actual field production data. The comparative analysis showed 12% error between our simple correlation and the Kinder Morgan model. For injecting CO2 in horizontal wells, the correlation could not be verified against the Kinder Morgan model, but the correlation followed the actual oil production in the field very closely.
This new model can be used effectively as a screening tool for predicting the performance of CO2 flooding in various locations in the Weyburn reservoir based on the data obtained from past waterflooding performance and the rate of CO2 injection. Hence, it can contribute significant savings in time and expense to the operating oil company. Also, this approach can be utilized for other potential CO2 flooding processes in reservoirs with histories and properties similar to those of the Weyburn field.
Does Polymer Stabilize Foam in Porous Media?
Authors: Shen C. , Nguyen Q. , Huh C. , Rossen W. R. 
Published: December 2007

Abstract
Addition of polymer has been proposed as a way to stabilize foam, especially in the presence of oil. This study probes the putative stabilizing effect of polymer on foam in terms of steady-state properties. Specifically, we tested the effect of polymer addition on the two steady-state foam regimes identified by Alvarez et al. (SPEJ, 2001).
For the two polymers (xanthan and partially hydrolyzed polyacrylamide), two oils (decane and 37.5° API crude oil), and an alpha-olefin sulfonate surfactant, it appears from coreflood pressure gradient that polymer de stabilizes foam modestly, raising water saturation and water relative permeability. The increased viscosity of the aqueous phase with polymer counteracts the effects of destabilization of foam. For the same polymers and surfactant, polymer does not stabilize foam in the presence of decane or 37.5 deg API crude oil relative to foam without polymer. Surface-tension measurements with these polymers and surfactant likewise showed no evidence of presence of polymer at the air-water interface that might stabilize foam lamellae between bubbles. This suggests that, for similar polymers and surfactants, addition of polymer would not give stronger foam in field application or stabilize foam against the presence of crude oil.
Complex behavior, some of it in contradiction to the expected two steady-state foam regimes, was observed. At the limit of, or in the place of, the high-quality regime, there was sometimes an abrupt jump upwards in pressure gradient as though from hysteresis and a change of state. In the low-quality regime, pressure gradient was not independent of liquid superficial velocity, but decreased with increasing liquid superficial velocity, as previously reported and explained by Kim et al. (SPEJ, 2005).
Reservoir Modeling for Mature Fields—Impact of Work Flow and Upscaling on Fluid-Flow Response
Authors: Meddaugh W. S. 
Published: December 2007

AbstractScoping studies using data from three mature fields suggest that simple workflows that use only essential stratigraphic and facies constraints are as good in capturing overall reservoir fluid flow response as complex, highly constrained workflows that use detailed stratigraphic and facies constraints. Thus, considerable time and cost saving may be realized during initial model building and updating if simple, but appropriate, workflows are used.The reservoirs studied include a Permian-age carbonate reservoir in New Mexico, an Upper Miocene deepwater clastic reservoir in California, and an Eocene-age shallow water clastic reservoir in Venezuela. Two dimensional cross section models of the deepwater clastic reservoir showed that cumulative production and water breakthrough times were essentially the same for models using the two major stratigraphic picks as for models constrained by 12 detailed stratigraphic picks. Three dimensional streamline simulation was used to demonstrate that adding facies and rock type constraints had little impact on recovery factors for a carbonate reservoir scoping project area consisting of 25, 5- spot waterflood patterns. Likewise, a very complex workflow for the shallow water clastic data set from Venezuela constrained by eight facies and 16 detailed stratigraphic picks yielded the same reservoir response as a simple, two facies, and four major stratigraphic picks constrained workflow. These studies suggest that for reservoirs with moderate to high net to gross (&gt;30-40%) or with small differences in the porosity vs. permeability trends of facies/rock types that simple geological modeling workflows are adequate for subsequent fluid flow simulation. Models generated using the shallow water clastic data sets and evaluated using three dimensional streamline simulation showed that varying the semivariogram range parameters by factors between 0.25 and 2 times the data driven range value also had little effect on reservoir response.An important issue surrounds the impact of up-scaling on fluid flow response. Vertical up-scaling by factors commonly used for full field simulation models has little impact on fluid flow response based on studies of the New Mexico carbonate reservoir and the shallow water clastic reservoir in Venezuela. However, areal up-scaling of models generated using a very fine 50 foot areal grid significantly alters the fluid flow characteristics and warrants additional study.
Oxygen-Free Acid-Stimulation in an Underground Gas Storage Well Completed With Prepacked Screens
Authors: Yntema S. , de Boer P. , Trompert R. A. , De Jonge R. M. , van Gellekom B. J. 
Published: December 2007

Abstract
A well at an Underground Gas Storage location of NAM was identified to be impaired, this resulted in a significant reduction of well performance and jeopardized the integrity of the well, and as such, it classified as a stimulation candidate. However, an acid stimulation treatment in a business-critical environment such as the Grijpskerk Underground Gas Storage in the Netherlands (total peak capacity 2000 MM Scf/D), can only be executed when well and facility integrity are fully ensured.
Corrosion in wells and at production facilities due to acid stimulation treatments are being reduced by the use of appropriate corrosion inhibitors. However, due to the introduction of oxygen in the treatment fluids, for example during loading, transportation, mixing and pumping down a well, fear for corrosion still remains. In order to minimize the risk of corrosion by oxygen, a process was developed, in which all treatment fluids were prepared such that oxygen levels were considered essentially oxygen-free. The process involved the use of purging tanks, mixing the treatment fluids with nitrogen, the addition of oxygen scavengers and dilution of back-produced fluids.
The efficiency of acid treatments in pre-packed screens completions can be enhanced by the use of coiled tubing and the right choice of jetting method. Pre-packed screens generally do not resist high differential pressures, and therefore, the impact pressure of the jetting fluid on the screen needs to be kept low. At the same time, thorough treatment coverage onto the screen and into the pores of the pre-packed sand is desirable in order to achieve optimal stimulation results. A novel rotating/pulsating coiled tubing jetting tool was used that produces, apart from the non-damaging low impact pressure, hydraulic vibrations created by the pulsating effects of the jets. This pulsating effect dislodges insoluble fines in the pre-packed screen, and opens pore space normally unaffected by chemical action of the treatment fluid. The rotating nozzles ensure complete wellbore coverage.
This paper presents a case study of an oxygen-free acid stimulation treatment, performed in a well, completed with pre-packed screens, at the Grijpskerk Underground Storage facility in the Netherlands. Contributing to the success of the operation was the cross-discipline preparation, the selection of the optimum coiled tubing jetting tool, the investigation of impairment mechanism, selection of treatment recipe in combination with screen integrity tests, development of a process to create an essentially oxygen-free environment and spent-acid back production strategy. A dedicated production and test program was designed, for which chloride ions, oxygen and pH levels were monitored at the production facility against pre-set criteria.
QT-16Cr Coiled Tubing: A Review of Field Applications and Laboratory Testing
Authors: Martin J. R. , Van Arnam W. D. , Normoyle B. K. 
Published: December 2007

Abstract
QT-16Cr coiled tubing was introduced as a commercial product in the spring of 2004. This high strength corrosion resistant alloy product was developed to offer a cost effective coiled tubing solution for both injection and secondary production applications in wet CO2 environments where carbon steel products may not be suitable.
This paper focuses on the results of two years of field applications and laboratory testing with the intent of defining the suitability and limitations of QT-16Cr as a completion string subjected to varying concentrations of CO2, H2S, chlorides and pH. The combination of actual fluid and gas analysis from wells where QT-16Cr has been employed will be compared to autoclave testing which simulates downhole conditions with applied stress on the tubing.
This paper also addresses the manner in which QT-16Cr has a positive effect on production system economics using several S. Texas wells as examples.
A review of field tests utilizing QT-16Cr as work strings will be covered. Attributes will be reviewed inclusive of abrasion characteristics when run inside 13 chrome production tubulars and low cycle fatigue performance data.
Both operators and service providers that have potential applications for corrosion resistant alloy coiled tubing should have interest in this update and overview regarding the performance of QT-16Cr coiled tubing.
Redevelopment a Mature Field for Production Acceleration: Intisar 103E Field, Libya
Authors: Senturk E. , Lahwel M. , Elghmari M. 
Published: December 2007

Abstract
This paper presents a successful re-development and production acceleration project of Intisar E Field, Upper Girs A, B & C reservoirs of the Zueitina Oil Company in Libya. The project was implemented from 1999 to 2002 on the bases of a simulation modelling study. The re-development plan comprised drilling 6 vertical injectors and 6 horizontal producers, and re-completion of existing 8 wells as commingled and/or dual producers. As a result of this project, the oil production potential of Upper Gir reservoirs was increased almost by three folds from average of 6,400 STB/D in 1999 to 20,000 STB/D in September 2002. The incremental reserves are predicted at 33.4 MMSTB until the year 2022.