bluuebunny/crossref_metadata_2025 huggingface dataset:
Production Increases at PDVSA Using an Improved SRP Control
Authors: Peterson R. , Smigura T. , Brunings C. , Quijada W. , Gomez A.
Published: December 2007

Sucker Rod Pumping (SRP) systems have used various control methods to optimize production, improve energy efficiency, and reduce maintenance. These systems typically use Rod Pump Controllers (RPCs) or timers to cycle the rod pumping unit on and off. Variable Speed Drives (VSDs) are occasionally used in conjunction with RPCs to improve operation by modulating pump speed. An improved SRP control that combines the RPC and VSD functions in an integrated system was installed on approximately 100 rod pumping systems at PDVSA starting in January 2004. The improved control resulted in a median production increase of 21%.

Embedded optimization controls in the VSD allow PDVSA engineers to preset a desired target pump fill based upon an Optimizer ID routine that samples production rates at various operating speeds and pump fill values over several days. The control subsequently adaptively modulates the pumping speed profile accordingly, thereby maintaining continuous operation at the identified optimal target pump fill. By maintaining a constant fluid level rather than the traditional cycling of fluid level between two limits, production losses associated with cycling above the target IPR well flowing pressure are eliminated. Furthermore, continuous and adaptive downhole pump speed control within each stroke allows the target IPR well flowing pressure to be reduced while improving equipment protection.

In addition, the VSD exercises the pump through controlled sequences that automatically identify other valuable system characteristics such as pump leakage, traveling/standing valve problems, pumping unit characteristics, counterbalance characteristics, and motor electrical parameters.
Modeling Transient Thermo-Poroelastic Effects on 3D Wellbore Stability
Authors: Farahani H. S. , Yu M. , Miska S. , Takach N. , Chen G.
Published: December 2007

The temperature difference between the wellbore drilling mud and the formation, especially in deep wells, causes volumetric expansion of pore fluid and rock matrix. Most existing models ignore the effect of convective heat transfer, which is a valid assumption for low permeability formations such as shales. However, convection plays an important role in controlling wellbore stability in high permeability formations such as sandstones.

A 3-D thermo-poroelastic model that accounts for the effect of convective heat transfer is developed in this study. Transient coupled pore pressure and temperature equations for non-isothermal conditions are developed based on conservation laws.

Thermal effects are generated by the temperature imbalance between the drilling fluid and drilled formations, and increase as the temperature imbalance increases. Cooling the formation is found to be helpful in lowering collapse pressure, resulting in a more stable borehole. However, it is also found that a formation is more vulnerable to fracture because cooling also lowers the breakdown pressure. A higher mud weight is required to fracture the formation when hot drilling fluid is used because hotter fluids increase the breakdown pressure. Also, a higher mud density is needed to prevent a wellbore from collapsing when a hotter fluid is being circulated through it.

The model presented in this study is useful for wellbore stability analysis for deep wells and deep water applications where mud temperature varies significantly along the well path.
Achieving Savings in Time-Sensitive Completion Costs: Results from Recent Single-Trip Multizone Frac-Packing Case Histories
Authors: Van Sickle E. , Womble A. , McKown M.
Published: December 2007

With rig costs and other time-sensitive completion costs rising, offshore operators must continually find ways to reduce operating costs while minimizing risk. Frac packing often involves expensive fluids, proppant and equipment. Single-trip multi-zone sand control completion systems are not new to the Gulf of Mexico, but the adaptation of these systems to facilitate frac packing has created new opportunities for the technology. Multi-zone, single-trip completion systems were first used offshore California in the 1980s to reduce completion costs in marginal fields. The initial system design was used successfully in several hundred wells to complete more than 900 zones. In the early 1990s, the system was modified to minimize rig time and reduce formation damage in the Gulf of Mexico by reducing formation exposure time to completion fluids. This paper will review the history of multi-zone, single-trip completion systems and discuss how the systems were adapted to facilitate frac packing, including modifications to allow for high pump rates and large sand or proppant volumes. The paper will also present detailed results of recent applications for several Gulf of Mexico operators that demonstrate the advantages of the technology over more conventional stack-pack completion methods.
The Application of Artificial Neural Networks With Small Data Sets: An Example for Analysis of Fracture Spacing in the Lisburne Formation, Northeastern Alaska
Authors: Kaviani D. , Bui T. D. , Jensen J. L. , Hanks C. L.
Published: December 2007

Artificial neural networks (ANNs) have been widely used for prediction and classification problems. In particular, many methods for building ANNs have appeared in the last two decades. One of the continuing important limitations of using ANNs, however, is their poor ability in analyzing small data sets because of overfitting. Several methods have been proposed in the literature to overcome this problem. Based on our study, radial basis functions (RBF) with stacked generalization can effectively decrease the error of the prediction when there is an underlying relationship between the variables. We have applied this method to determine the factors controlling and related to fracture spacing in the Lisburne Formation.

Comparing our results with those from other ANN methods, we find that the proposed method gives a substantially smaller error than alternative methods. The errors in predicted fracture spacing for the Lisburne using the conventional ANN methods are about 50 to 200% larger than those obtained using the proposed method. By having a method which predicts fracture spacing more accurately, we were able to more reliably identify the effects of such factors as bed thickness, lithology, structural position, and degree of folding on the spacing.

In petroleum engineering and geosciences, there are many cases where the number of data is limited because of expense or logistical limitations, e.g., limited core, poor borehole conditions, or restricted logging suites. Thus, the methods used in this study should be attractive in many petroleum engineering contexts where complex, non-linear relationships need to be modeled using small datasets.
Automated Reporting Using Rig Sensor Data Enables Superior Drilling-Project Management
Authors: Thonhauser G. , Mathis W.
Published: December 2007

An integrated process management system is the key to success of an enterprise working in the exploration business. Classic project management consists of the creation of an expectation, the well plan, appropriate process monitoring and the post analysis of the project through the comparison of the expectation and the actual process. As a result of the post analysis lessons learned are compiled.

The quality of this traditional project management is strongly dependent on information flow. State-of-the-art reporting on a drilling rig is recurrent human reporting such as the classic morning report, although there are a lot more sources of information available.

The presented concept of automated reporting, away from human observations, is ensured by utilizing rig sensor data. The automated reporting provides management, engineering and operations with the level of detail and granularity of objective, high quality information they need. It also offers the possibility of knowledge management and exchange at the same organizational level providing different "views" of the same project. This means that operations receive information on detailed process parameters, engineering on essential design variables for future wells and management on cost. Along with traditional project management this new automated reporting enables continuous, real-time project tracking and analysis even with a declining workforce because all information is bundled and under "central control".

Automated reporting is able to cover the life-cycle of every well construction and allows the establishment of high quality benchmarks for future planning and project evaluation in realtime. Moreover, it enhances the learning and experience level of every single person involved in the process.

Finally, it offers the possibility to manage multiple concurrent projects such as a company's fleet of drilling rigs to be able to optimize resource allocation and project economics.
Real-Time Reservoir Surveillance Utilizing Permanent Downhole Pressures—An Operator's Experience
Authors: Chorneyko D. M.
Published: December 2007

Permanent downhole pressure gauges supply important information for reservoir surveillance and management. Technology has evolved over the more than 40 years since the first installation. Service companies have made significant improvements to the components of a permanent downhole gauge installation for a well. The components include gauges, housing, cable, connections, and acquisition systems. Installation and use of these gauges has become routine in many situations because of the improved reliability and the value of information that the gauges provide.

Pressures from permanent downhole gauges can be examined almost as soon as they are acquired, depending on communication speed. The data is used for many applications including pressure monitoring, interference testing, water and gas injection monitoring, transient well testing, evaluation of well performance, reducing the flowback time of new wells, monitoring hydraulic fracturing operations, and monitoring pump inlet and outlet pressures for pumping wells.

On the practical side, there are issues associated with the data that these gauges collect. Vast amounts of data are being gathered continuously at intervals down to one second over numbers of years. This data must be communicated from the well to the office. Since the data is an asset, it must be stored and archived. Individuals require access to the data at different times, for different reasons, and at differing resolutions. Interpretation of the data poses new challenges as there is more hidden in the long term pressure record than just a collection of drawdowns and buildups. The data contains information about parameters changing during short and long time intervals both near the well and in the reservoir. As more and more permanent downhole gauges are deployed, maximizing the corporate benefits becomes an asset management issue. Companies are faced with stewardship of the investment, communicating learnings across the organization, developing or acquiring software tools for data management and analysis, proposing and supporting industry- wide standards for consistent data capture and communication, and integrating data into work processes and into applications such as smart wells and smart fields.
Estimation and Removal of Tidal Effects From Pressure Data
Authors: Zhao Y. , Reynolds A. C.
Published: December 2007

We consider field pressure data from two wells, one offshore and one onshore. The onshore well is shut-in and experiences only a very small pressure decline due to inter-ference whereas, in the offshore case, the late time buildup data appears to be severely corrupted by ocean tidal effects. The objectives in both cases are to determine the tidal signal which can be used to estimate formation compressibility and to remove the tidal signal from the measured data.

For the onshore well, we use a Savitsky-Golay filter to smooth the pressure data. Subtracting the smooth data from the measured signal yields a modified signal which ideally represents the earth tidal signal plus measurement error. As the main harmonic components of the earth tidal signal are known, we perform a least-squares fit of the modified pressure data with a series of sines and cosines which contain only the known frequencies of the earth tide. By subtracting the series obtained by least squares fitting from the true signal, we remove the effect of the earth tide.

In the offshore case, the time span of the data that is severely affected by tidal effects is too short to use the Savitsky-Golay filter with confidence. As the reservoir pressure change due to the tides is well-approximated by a damped and delayed version of the sea floor response, a least squares fit of the data with a function which follows the underlying buildup trend plus an attenuated-delayed response of the measured seafloor pressure trace allows one to obtain a good estimate of the attenuation factor and time delay so that the tidal component of the bottom-hole pressure change can be determined and removed from the measured pressure.
Optimizing the Productivity of Gas/Condensate Wells
Authors: Shi C. , Horne R. N. , Li K.
Published: December 2007

Gas-condensate reservoirs exhibit complex phase and flow behaviors due to the appearance of condensate banking in the near-well region. A good understanding of how the condensate accumulation influences the productivity and the composition configuration in the liquid phase is very important to optimize the producing strategy, to reduce the impact of condensate banking, and to improve the ultimate gas recovery.

This study addressed several issues related to the behavior of the composition variation, condensate saturation build-up and condensate recovery during the gas-condensate producing process. A key factor that controls the gas-condensate well deliverability is the relative permeability, which is influenced directly by the condensate accumulation. The accumulated condensate bank not only reduces both the gas and liquid relative permeability, but also changes the phase composition of the reservoir fluid, hence reshapes the phase diagram of reservoir fluid and varies the fluid properties. Different producing strategies may impact the composition configuration for both flowing and static phases and the amount of the liquid trapped in the reservoir, which in turn may influence the well productivity and hence the ultimate gas and liquid recovery from the reservoir. Changing the manner in which the well is brought into flowing condition can affect the liquid dropout composition and can therefore change the degree of productivity loss.

In this study, compositional simulations of multicomponent gas-condensate fluids were conducted at field scale to investigate the composition and condensate saturation variations. Different producing strategies have been compared, and the optimum producing sequences are suggested for maximum gas recovery. A core flooding experiment with two- component synthetic gas-condensate was designed and constructed to model gas-condensate production behavior from pressure above the dew-point to below. Experimental observations of gas-condensate production confirm the dramatic changes in the liquid composition seen in the simulations.
Sustained Competitive Advantage Through Structured Mentoring
Authors: Arango G. , Han P. , Rousseau M.
Published: December 2007

"Knowledge is like money. To be of value, it must circulate, and in circulation it can increase in quantity and, hopefully in value." (Louis L'Amour).

Sustained success and steady growth require organizations to develop and retain a core of culture, relationships and critical knowledge and skills. Capitalizing on the strengths of several disciplines such as competency-based training, knowledge management, and structured mentoring programs, organizations can reach these goals and offer their employees opportunities for professional development and career advancement that would not otherwise be possible. In this paper, we discuss an approach to structured mentoring aimed at the effective and reliable transfer of corporate culture, relationships, and knowledge. We identify key practices and tools and share lessons learned from experience.
3D Numerical Simulator for Horizontal-Well Gravel Pack
Authors: Ojo K. P. , Osisanya S. O. , Ayeni K. B.
Published: December 2007

A 3-D numerical simulator for horizontal well gravel packing is developed. The model was developed based on the fundamental laws of physics by solving for an overall conservation of forces during the placement of the gravel in the horizontal well bore. The equations of continuity, motion, and deposition are simultaneously solved to give a 3-D solution of the gravel pack process. The modeling equations consist of five partial differential equations (PDEs) with five dependent variables, all of which were solved simultaneously. The system of PDEs was approximated using the central-difference finite-difference approximations method. The settling effect of slurry using the type of fluid, proppant and flow conditions existing in gravel pack operations in horizontal wells were also included in the model.

The model is used for simulating the gravel pack process and determining the effectiveness and pack efficiency of the gravel pack job. This 3-D simulator can be used to simulate special situations in which significant leakage into the formation occurs during gravel packing. The simulator is particularly suitable for deep horizontal wells because the hindered settling effect prevalent in the long vertical section of deep horizontal wells is accounted for in the modeling equations. The simulator was illustrated by simulating some horizontal gravel-pack jobs reported in the literature.
Tracing Streamlines on Unstructured Grids from Finite Volume Discretizations
Authors: Matringe S. F. , Juanes R. , Tchelepi H. A.
Published: December 2007

The accuracy of streamline reservoir simulations depends strongly on the quality of the velocity field and the accuracy of the streamline tracing method. For problems described on complex grids (e.g., corner-point geometry or fully unstructured grids) with full-tensor permeabilities, advanced discretization methods, such as the family of multipoint flux approximation (MPFA) schemes, are necessary to obtain an accurate representation of the fluxes across control volume faces. These fluxes are then interpolated to define the velocity field within each control volume and streamlines are integrated. Existing methods for the interpolation of the velocity field and integration of the streamlines do not preserve the accuracy of the fluxes computed by MPFA discretizations.

Here we propose a new method for the reconstruction of the velocity field with high-order accuracy from the fluxes provided by MPFA discretization schemes. This reconstruction relies on a correspondence between the MPFA fluxes and the degrees of freedom of a mixed finite-element method (MFEM) based on the first-order Brezzi-Douglas-Marini space. This link between the finite-volume and finite-element methods allows the use of flux reconstruction and streamline tracing techniques developed previously by the authors for mixed finite elements. After a detailed description of our streamline tracing method, we study its accuracy and efficiency using challenging test cases.
Subsea Multiphase Pressure Boosting and a New Approach for Speed Control Using a Hydrodynamic Variable-Speed Drive
Authors: Scott S. L. , Xu J. , Lenz C.
Published: December 2007

Interest in the subsea deployment of multiphase pumps and wet-gas compressors has grown as companies search for methods to improve recoveries and economics for subsea wells. Subsea pressure boosting technologies are also seen as vital in providing access to deepwater oil and stranded gas reservoirs. While multiphase pumping has been proven onshore, operators have been hesitant to deploy this technology subsea due to the high costs and inherent risks associated with the first application of a new technology. This paper examines various types of subsea multiphase pumps and wet-gas compressors and discusses the special issues associated with subsea operation. Multiphase pressure boosting requires a wide torque and speed range due to significant load changes, triggered by changes in the gas volume fraction (GVF). This paper introduces and describes a hydrodynamic variable speed drive that can be utilized with both multiphase pumps and wet-gas compressors. This variable speed drive is arranged between a fixed speed motor and the multiphase boosting device and appears to offer several distinct advantages for subsea operation. The Voith Turbo EL6 torque converter was installed and tested with a twin-screw pump under multiphase condition. Results of testing under slug flow conditions are presented along with observations regarding the use of a torque converter for speed control.
Effect of Layered Heterogeneity on Fracture Initiation in Tight Gas Shales
Authors: Suárez-Rivera R. , Green S. J. , McLennan J. , Bai M.
Published: December 2007

Hydraulic fracturing is the requisite methodology for completing nano-darcy matrix permeability tight gas shales. Commercial success in producing these reservoirs depends to a large extent on successful hydraulic fracturing. There is growing evidence that initiating hydraulic fractures from horizontal wellbores is often difficult, and requires abnormally high treating pressures. In this paper, we show that the combination of high stiffness, significant elastic anisotropy, and coupled elastic property and horizontal stress development, in tight gas shale reservoirs results in complex near-wellbore stress concentrations, not observed in isotropic rocks. Using finite element analysis (FEA) and numerical modeling, with continous mechanics and transverse anisotropic elasticity, we provide insights on the stress concentration resulting from various conditions of stress (normal and reverse faulting) and material properties. We also provide a simplified methodology for first-pass calculation of these stress concentrations, and thus for predicting the potential for problems during fracture initiation. Modeling near-wellbore effects in horizontal completions in anisotropic shales is straightforward. However, the calculations require a larger set of material properties (4 elastic constants), as well as in-situ stresses, and reservoir pressure.
Production Improvement Water Shutoff for White Tiger Field
Authors: Chan Keng Seng , Lam Duong Danh , Ivanov Aleksey , Apisitsareekul Kiam P. , Hai Le Viet , Nghi Nguyen Chinh , Hung Vuong Quoc , Lang Le Dinh
Published: December 2007

Oil production from some of wells in the White Tiger field producing from a fissured Basement reservoir; have been impaired by excessive water production. Excess water not only reduced the artificial lift efficiency, but also imposed various damages to the oil zones.

Since 2002, a joint industrial project was set up to study the feasibility of performing water shutoff treatments in the open-hole completion oil wells. The study involved evaluation of a high temperature polymer base water shut-off fluid for deep penetration of the fissure formation and a micro-fine cement system for sealing off the water entries. Based on this study, a cost-effective chemical treatment method was progressively developed. In 2005, the treatments were performed through-tubing with and without isolation packers.

Two Candidate wells were having 6.5″ open-hole size, at approximately 4,200 meter TD, and 150 deg C reservoir temperature. The water cut were 95% in one well and 30% in the other well. It was found that these two wells certainly had big difference in fluid injectivity, and original designed treatment was modified on site. This paper summarizes key lessons learnt including tool and packer conveyance, mixing and pumping of water shut-off fluids under offshore rig and wellsite conditions. It also shares a method of post treatment production evaluation and suggests operational change to improve the production.
Modern Approach to Estimation of Uncertainty of Predictions With Dynamic Reservoir Simulation—A Case Study of a German Rotliegend Gas Field
Authors: Junker H. J. , Plas L. , Dose T. , Little A. J.
Published: December 2007

A deep German onshore Rotliegendes gasfield in a complex sedimentary and structural environment is subject to evaluation of the remaining potential for additional wells and possible recovery acceleration.

A graben structure filled with aeolian sediments in an overall depth of about 4900m comprises the dry gas bearing reservoir. The field is developed by a limited number of expensive wells with a relatively wide well spacing. The wells face complicated drilling conditions and a necessary deviation to honour environmental issues which severely limit the number of well site locations.

The quality of the 3D seismic is limited because of Zechstein salt intrusions in the overburden. Hence the structural and interpreted fault models are subject to significant uncertainties. Characterisation of aeolian sedimentary facies distribution and quality, which suffers from diagenetic effects, is achieved by a geostatistical approach. The model is mainly based on information from cores and logs. Seismic information could only be used to guide the distribution of the aeolian reservoir facies and a probably unproductive fanglomerate facies type.

One main question is the level of compartmentalisation of the field due to faults and flow barriers related to reservoir facies distribution. During the dynamic modelling process possible scenarios are checked against the observed production data regarding communication and GIIP distribution. This gives a range of possibilities leading to a significant uncertainty regarding the prediction of future production and the effect of acceleration wells. There is room for only a few more wells. The decision where to place these is supported by the integrated modelling approach. This has been chosen to address a wide range of uncertainty of both static and dynamic effects. The static effects have been addressed by a combination of geostatistical static reservoir modelling with fully 3D static uncertainty estimation.

The basis for the dynamic modelling part is a family of realisations defined by a process to identify "most diverse" representative scenarios out of bigger number of geological realisations. Computer aided history matching, experimental design and proxy solutions gave a very effective approach to handle the uncertainty estimation with the dynamic reservoir simulation. The fully integrated workflow allowed an optimized process to estimate the uncertainty of prediction within a limited time frame. The main subject of this paper is the process of dynamic reservoir simulation using these techniques and discussion of the results.
Fracture Acidizing: What Role Does Formation Softening Play in Production Response?
Authors: Nasr-El-Din H. A. , Al-Driweesh S. M. , Metcalf A. S. , Chesson J.
Published: December 2007

Fracture acidizing of carbonates has yielded increases in production in many areas of the world, but depending upon rock strength and reservoir closure pressure this response may be lower than expected. Also, as a result of rock strength and closure pressure, production may decline at a higher rate than after a proppant fracture treatment.

Laboratory results are presented describing the effect on strength reduction of limestone and dolomite formation samples after exposure to various acid systems. Formation samples were dry, saturated with potassium chloride water or saturated with synthetic oil prior to testing. Samples were exposed to neat, emulsified, gelled and crosslinked 15 wt% hydrochloric acids and each exhibited a differing effect on rock strength reduction. In addition, production responses are presented and compared with regard to type of acid system used for stimulation.
Underbalanced Operation Can Extend Its Antennae To Breach the Barriers of Conventional Method
Authors: Liu Gang , Qin Wengui
Published: December 2007

Under-balanced drilling has been using in China for several years. UBD technology can reduce mud weight in the maximum way, and is a valuable method of minimizing formation invasion related problems. Some oilfields have found its strongpoints in exploration and development. This paper demonstrates that UB sometimes can be used to break through the barriers of HPHT, to prevent the H2S from branching out, to solve the problem of narrow margin between the formation fracture pressure and pore pressure, to find a new producing pay, and to drill through the lost circulation zone etc. So it could be a way of using UB tools or UB technology to solve the engineering difficult problem and to keep the well in safe, at the same time UB has shortage itself and will bring some troubles if it not be properly designed or controlled. Several problems in using UB tools and technology will be discussed, especially on the methods of pressure control. To enhance the reliability of UB practice, a new design choke control panel has been used in well site. This equipment has the multifunction of drilling engineering data acquisition, data transimission and storege, and especially has the function of pressure automatic control. The result of laboratory test illuminates that the function of software and data acquisition of the system work well. The result of 3 well site tests and 2560 hours work illuminates that the functions of hardware, software and the pressure auto-control of the equipment work well. It is valuable for improving UBD operation and safety. UB tools give us the approach of reducing mud density and offer the well safety in a certain extent, so we can use it in UB and NBD (near balance drilling), just for when and how much the new productivity and enhancement production has been gotten, not for when and how much the pressure difference has been remained.
Multicomponent OBC (4C) Imaging Over Pamberi, LRL Block, Offshore Trinidad
Authors: Johns T. D. , Vito C. , Clark R. , Sarmiento R.
Published: December 2007

Results from the P-P and P-Sv prestack time migration of a 2.5D four-component (4C) OBC seismic swath test acquired in 2004 over the Pamberi area in Block Lower Reverse L offshore Trinidad, are presented. The 4C swath acquisition consisted of twelve 100-m spaced source lines, shot into two parallel 15-km OBC receiver lines, separated by 400 m. A description of the processing applied to the recorded multicomponent (4C) seismic data, through curved-ray anisotropic Kirchhoff prestack time migration for both the compressional P-wave and mode-converted PSv-wave, is provided. Mode-converted shear-wave data acquired from 4C surveys allow for imaging where conventional seismic data are perturbed due to the presence of shallow gas and/or fluid in the pore spaces of the rock. Furthermore, mode-converted shear waves propagate with a different raypath than that of the compressional wave, thereby providing an alternative illumination of the subsurface target. As both the compressional P-wave and mode-converted S-wave record independent measurements of the same subsurface, more reliable rock properties can be uniquely determined, allowing for improved reservoir characterization and lithology prediction.

A conventional streamer 3D survey was acquired over the Pamberi area in 2003, but failed to image or resolve adequately the target reflectors comprising the reservoir under the main growth fault. Therefore, the purpose of the 4C swath test was to evaluate the potential of long-offset multicomponent technology for resolving stratigraphic interpretation in complex areas with challenging geology.

The processed images from both the compressional wave and mode converted shear waves are shown to illustrate the improvement in resolution at the reservoir prospect level which were not clearly evident on the previous conventional towed streamer 3D data volume.
Laboratory Hydraulic Fracturing Test on a Rock With Artificial Discontinuities
Authors: Casas L. , Miskimins J. L. , Black A. , Green S.
Published: December 2007

The design and subsequent results of a hydraulic fracturing test performed on a large block of high modulus and low permeability rock (Colton sandstone) are presented. The focus of this experimental study was to assess the effects of discontinuities on hydraulic fracture growth. A high viscosity fluid was used in order to provide fracture growth similar to actual field conditions. Fracture growth and its internal fluid pressure were monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure probes and showed a distinct fluid lag region (i.e., a lower fluid pressure region close to the fracture tip). The controlled laboratory experiments showed planar fracture propagation trends as expected from three-dimensional modeling.
The Evolution of Advanced Well Completions Results in Enhanced Well Productivity and Recovery in Saudi Aramco's Offshore Fields
Authors: Al Qudaihy D. S. , Al Qahtani H. B. , Sunbul A. H. , Hembling D. , Salerno G.
Published: December 2007

The Offshore sandstone reservoirs in Saudi Arabia are characterized by high production potential due to the nature of the reservoir, consisting of clean coarse sand with active bottom water aquifer and in some areas, a gas cap as drive mechanisms.

In recent years, horizontal wells have replaced conventional wells due to their improved deliverability and recovery efficiency. The initial completion method selected by Saudi Aramco for the horizontal wells was mainly cased hole cemented with selective perforation strategy. This completion method was troubled by non-uniform flow profiles, which drastically shortened the well production life reducing the benefit associated with the planned horizontal wells.

This paper will describe the concept of an innovative openhole completion strategy that has increased well productivity and recovery compared to past horizontal completion methods. The paper will show the evolution starting with the use of openhole completions completed with passive Inflow Control Devices (ICD) allowing production optimization by delivering uniform inflow along the entire horizontal section. The paper continues to discuss the benefits associated with the integration of the passive inflow control system with artificial lift (In situ gas lift and Electrical Submersible Pump (ESP) and finally reveals plans to couple passive inflow control with active intelligent well completion technology for multilateral wells. Actual field data will be presented to validate findings and support conclusions.
Advanced Technology to Reduce Water Cut: Case Studies from the Pemex Southern Region
Authors: Romo G. A. F. , Leyva H. H. , Aguilar R. B. , Campos C. C. , Eoff L. , Darlrymple D.
Published: December 2007

This paper presents the results of a successful application of a new-generation polymeric relative permeability modifier (RPM) that enables treatments to reduce water cut without workover equipment. The new RPM can be bullheaded into open intervals without the need for isolating water zones from hydrocarbon zones. This treatment was applied to several wells in the Pemex southern region. As a result of the treatment, the productive life of the wells has been extended, with a gradual decrease in water cut. These results indicate high potential profitability values for mature fields with high water cut requiring a simple, low-cost treatment without the need for workover equipment or shut-in times. The new treatment can increase the hydrocarbon recovery percentage in sands that in all probability otherwise would be destined for abandonment.

This paper describes the treatment methodology, which begins with problem identification and an understanding of the origin of the water breakthrough. Next, the paper describes the new technology, which utilizes hydrophobically modified water-soluble polymers and explains how applying such polymers can control water selectively. In addition, the detailed execution of the treatment is described, followed by the very positive production results after the treatment. The results of this low-investment, high-profit technology are very promising for other wells under similar conditions in which workovers with conventional technologies would be cost-prohibitive.
Coiled-Tubing-Deployed Re-Entry Whipstocks—Technology Overview and Case Histories
Authors: Mackenzie G. R. J. , Wilson S. B.
Published: December 2007

This paper will focus on providing the reading audience with a general overview of the practice of utilizing a whipstock methodology with the conveyance method of coiled tubing in order to create a casing / liner window. The overview will discuss general practices, tool selection criteria and provide case history demonstration of such. The case histories demonstrated will be representative of placement of the whipstock with both electric wireline and coiled tubing with actual window milling being performed with coiled tubing and workover motors. The case histories will encompass monobore applications, through tubing re-entry environments, fluid operations and also under balanced nitrogen driven applications.
Impact of the Viscosity Reduction on the Productivity Index Using a Simulation Study in Two Networks in the Gulf of Mexico
Authors: Ramîrez-Garnica M. , Cazarez-Candia O. , Clavel-López J. , Nares R. , Schacht P. , Cabrera M.
Published: December 2007

The use of catalysts in crude heavy oils can improve substantially their viscosity, API and reduce the content of porphyrins, sulfur, and asphaltenes [1]. In this work a simulation study of the heavy crude oil production in networks (localized in the Golf of Mexico) was done to evaluate the effects of a smaller viscosity and a bigger API on the Productivity Index (J).

This work can be applied to study the increment of the J as well as the savings of operation costs in surface to transport and treatment of heavy oil before send it to refineries.

Simulation was done in two networks: first one, Network I performed by 8 wells offshore producing 13 °API crude oil, and the second one, Network II, producing 8 °API crude oil. In both cases, J is referenced here considering one effect of the catalyst benefits: mainly reduction of viscosity. In the case of the network producing 13 °API crude oil (with 145.26 cP @ 25°C, dead oil) the actual global J is in total 1201.5 Barrels per Day per psi (BPD/psi), and accordance to the simulation (with a modified viscosity to 1.08 cP @ 25°C) the new global J should be 5411.26 BPD/psi, which it should represent an increase of 350.38 %. In the second net similar result was obtained, the actual global J is about 549.52 BPD/psi (with a viscosity of 515 cP @ 25°C, dead oil) while the simulation result gives a global J about 2062.57 BPD (with a viscosity of 133.9 cP @ 25°C), which would represent an increase about 275.34 %.

The significance of this simulation results is very important since the economical point of view because of the better quality of the improved oil and saving costs avoiding surface treatment previous their transport to refineries.
The Development of a New Function To Improve Waterflood Predictions After Breakthrough: Field Cases, Maracaibo Lake—Venezuela
Authors: Soto B. R. , Pérez V. O. , Montiel E.
Published: December 2007

One of the most important parameters calculated by reservoir engineers in a waterflood project is the variation of the average water saturation with time to estimate the recovery factor. For years, that average water saturation after breakthrough has been obtained by finding the intersection of the tangent to the fractional flow-water saturation curve, fw vs. Sw, at fw = 1.0. However, this technique is subjected to errors because it is difficult to determine the exact point where the tangent to the fractional flow curve intersects the curve.

This paper discusses the development of a new function that matches with all fractional flow calculation from relative permeability displacement data and oil-water viscosity ratios. That new function has four parameters that vary according to mobility ratio. The advantage of this new function is that its derivative can be used to calculate the average saturation after breakthrough and give more accurate results in estimating the waterflood predictions and the volume of oil displaced.

We present a procedure to determine the four parameters of the new general function and the advantages of its application with field examples from some reservoirs in the literature and from Maracaibo Lake, Venezuela.
Test Design for Vertical Permeability Determination from a Conventional Pressure-Buildup Test
Authors: Ehlig-Economides C. A. , Nduonyi M. , Abiazie J.
Published: December 2007

Vertical permeability magnitude is critical to well trajectory and/or completion design whenever the oil is either overlain by a gas cap or underlain by an aquifer or whenever a slanted or horizontal well is planned. Various authors have provided ways to determine horizontal and vertical permeability from a pressure transient test in a well with a limited entry completion. However, none indicate a test design that will ensure that the vertical permeability can be determined.

This paper provides the necessary test design considerations for horizontal and vertical permeability determination from a conventional pressure buildup test. A standard limited entry model for the pressure transient behavior is used to determine timing for the start and end of key flow regimes for the transient interpretation. Equations that can be used to design a test for vertical permeability determination are also used to indicate ranges of reservoir, fluid and well properties that result in a successful test.

A quick look analysis procedure enables estimation of horizontal and vertical permeability directly from a log-log diagnostic plot of pressure change and its logarithmic derivative. Examples illustrate test design and interpretation applications and demonstrate that determination of vertical permeability is possible even when wellbore storage masks early radial flow and an overlying gas cap and/or underlying aquifer prevent the appearance of late radial flow.
The Role of Independents in the Oil and Gas Industry
Authors: Wadood S.
Published: December 2007

The Oil Industry has been witnessing many rapid developments recently. A tough competition is arising between Super Majors and National Oil Companies (NOC). Eight of the largest 10 E&P in the world are NOCs. Small Independent producers, engaged primarily in production development found a niche market. Presenting almost no competition to NOC or IOC, they offer a solution for many assets, which are of no current interest to major oil companies.
Developing of Fully Automatic Webpage Simulator for Single-Well Study
Authors: Ibrahim M. , Wattenbarger R. A.
Published: December 2007

Reservoir simulation is widely used to solve research problems as well as actual field problems. This is due to the limitation of analytical solutions to deal with the heterogeneity of the reservoirs and non-linearity of the diffusivity equations (i.e., for gases, properties changing with pressure). Another reason is its ability to be used in predictive methods for reservoir management purposes. The advancement of computer hardware and software technology and development of numerical solution methods have been also the factor for the increased use of reservoir simulation in petroleum industry.

Complex reservoir problems usually need a large and complex computer program. However, in some cases, a fairly small and simple computer program is enough to adequately model reservoir conditions. The main problems in using commercial simulators are grid system especially for hydraulic fracture well, dealing with the complex menus for each data component, and the time required entering the production history.

In this study, we present the fully automatic webpage simulator which has the following abilities 1) automatic gridding for single or double porosity reservoirs, 2) automatic gridding for hydraulic fractures, 3) linking to the company database in calling the production history and running predictions, and 4) design to be easy in using. The first version illustrated in this paper is already tested and used by El Paso Production Company for modeling single gas wells. The well design menus for this simulator allow users to do simulation for single well with just a few mouse clicks without spending much time in entering any data due to this simulator have the ability to load the data from the database.
Successful Implementation of Well Management to Increase Hydrocarbon Production: A South Region of PEMEX E&P Case History
Authors: Arévalo-Villagrán J. A. , Gutiérrez-Acosta T. , Ascencio-Cendejas F. , Cinco-Ley H. , Lozada-Aguilar M. A. , Lysandrou M.
Published: December 2007

An integrated analysis of technical information from 459 wells that were shut in or having production problems within five Integrated Business Units in the Southern Region of PEMEX E&P, identified production increase opportunities of more than 145,000 STB/D of oil and 323 MMscf/D of gas. This paper presents the applied methodology and the results obtained from a project based on well management to optimize the recovery of hydrocarbons of the identified opportunities within these business units with minimum investments. The successful implementation of this project was based on the careful selection of highly qualified technical personnel that formed the nucleus of the working multidisciplinary teams that contributed to the increase of well productivity from the selected fields. The implementation of the concept of team work coupled with the application of selected technologies to identify and exploit potential opportunities made it possible for these business units to increase the production of crude oil over 67,635 STB/D and gas to over 111 MMscf/D from workover of 179 wells within 9 months thus achieving a production increase of 7.95 MMSTB of oil and 12.8 Bscf of gas. This increase in production made possible for this region to maintain a production plateu of 500,000 STB/D and 450 MMSCFD, offsetting natural production decline and loss of production due to a strong water invasion of wells. A profit/cost ratio of 15.1 has been obtained. In addition to the value added of production increase through this visionary management approach, the following benefits were obtained: learning and applying the team work approach of well productivity, adaptation to a new cultural change of working as teams to solve difficult problems, training and transfer in diverse methodologies, and software technologies from the interdisciplinary teams to the technical personnel of PEMEX E&P, and specific well data information certified that can be used to evaluate diverse reservoirs studies.