bluuebunny/crossref_metadata_2025 huggingface dataset:
Numerical Simulation to Design and Analyze Pressure Transient Tests in a Shaly, Interbedded Reservoir
Authors: Sinha S. P. , Al-Qattan R.
Published: December 2007

Analytical methods of pressure transient analysis are based on idealized well and reservoir configurations. As such, they have a limited scope in describing the reality. In practice, there is a need to interpret pressure transient tests with complex well completions, reservoir shapes, layering and complex reservoir structures. This is facilitated by the high precision modern pressure gauges, which can reveal details. Numerical simulation becomes a necessity in such complex cases as shaly interbedded reservoirs of Greater Burgan Field with moderate to high heterogeneity.

In the present work, two cases of pressure transient tests in an interbedded reservoir have been discussed. The first case is that of multiple perforations in multiple permeability zones having variable cross-flow. The second case is also that of well completed in an interbedded reservoir but with the presence of a fault and nearby oil-water contact (OWC). The analysis has been attempted using analytical methods, numerical simulation with PEBI grid and radial model. The results have been analyzed to discover the superiority of numerical simulation with PEBI grid over other methods of analysis.

The main results and conclusions of this paper are as follows: The analytical methods provide initial model review and should remain an integral part of the workflow for doing numerical simulation with speed.The PEBI grid based numerical simulation of pressure transient test provides the best answer in wells completed in an interbedded reservoir with heterogeneity. This may be due to the accurate computation of inter-block transmissibility for heterogeneous formations.The automatic meshing and fast solver for finite element simulation provides speedy simulated responses even in a complex case.An appropriate test design of pressure transient test is achieved using the numerical simulation. The test duration and rate scheduling should be pre-determined to achieve the test objective.
Gas Hydrate Production Technology for Natural Gas Storage and Transportation and CO2 Sequestration
Authors: Masoudi R. , Tohidi B.
Published: December 2007

Proposal

Gas hydrates (or clathrates) are group ice-like crystalline compounds, which form through a combination of water and suitably sized ‘guest’ molecules under low temperature and elevated pressure conditions. Within the clathrate lattice, water molecules form a network of hydrogen-bonded cage-like structures, enclosing the guest molecules, which generally comprise of low-molecular diameter gases (e.g., methane, ethane, propane, carbon dioxide (CO2), etc).

Although hydrate formation can pose serious flow assurance problems in oil and gas industry, gas hydrates have great potential for positive applications – turning a long standing problem into a potential benefit. Two important properties of hydrates are their very high gas to solid ratio, 1m3 of hydrate may contain up to 175m3 of gas (at standard conditions), and self preservation effects which make them feasible to be transported at atmospheric pressure. They thus present a novel means for gas storage, transportation and delivery, with consequent potential applications in a wide variety of areas, including exploitation of remote gas fields, CO2 sequestration, etc. However, a major barrier to the development of hydrate technology is the current lack of an economical means for the mass-production of solid hydrate in a manageable form.

In this communication, a literature review with a critical evaluation has been conducted on the various reported hydrate production techniques to better understand the production process and identify any shortcomings of such techniques. In addition a new technique is proposed to produce hydrate in which dry hydrate is formed in especially designed reactor in the presence of excess gas. The technique has been applied to production of NG hydrate for NG storage and transportation purposes and CO2 hydrate for application in CO2 sequestration. The preliminarily promising results of series of tests carried out on a NG and CO2 hydrate formation are presented along with an evaluation of atmospheric hydrate self-preservation and dissociation rate versus time and temperature.
A Novel Technique to Acidize Multilateral Open Hole ER Horizontal Wells Drilled in Carbonate Formations
Authors: Nasr-El-Din H. A. , Al-Habib N. S. , Al-Khamis M. , Jemmali M.
Published: December 2007

A new development strategy used by Saudi Aramco for carbonate reservoirs is to drill multilateral, extended reach, horizontal and fishbone wells. This strategy has a significant impact on reducing the development cost per bbl of oil produced, by drilling less wells and requiring less offshore platforms. This is also applied for the development of carbonate reservoirs in highly populated areas.

Drilling multilateral wells is intended to maximize reservoir drainage and minimize water production due to water coning. However, inherent problems with these wells are poor accessibility and uneven acid distribution during matrix acidizing, especially in reservoirs with high permeability streaks. This paper discusses an innovative approach to treat multilateral wells. This technique comprises mechanical diversion in the wellbore and chemical diversion in the formation.

In the past, reentry access to sidetracks from an open hole main wellbore was not possible. This prevented remedial operations on individual laterals and precluded effective reservoir management. To selectively enter and stimulate the desired lateral, a coiled tubing conveyed orienting tool was used. This ensured better acid distribution over the wellbore. To enhance acid diversion in the formation, a viscoelastic surfactant-based acid system was employed.

Well "A" is an offshore dual open hole multilateral horizontal well with a motherbore length of 2,256 ft and a lateral section of 3,558 ft. The lateral was rotary jetted with acidic brine during the completion phase, but the well did not sustain flow after a nitrogen gas lift.

A special CT conveyed multilateral tool was successfully used to enter the lateral. A viscoelastic surfactant-based acid was utilized to remove formation damage induced by drilling fluids, and to enhance the permeability of the formation in the critical wellbore area.

The well responded to the acid treatment and its production exceeded expectations. Challenges, design criteria, field treatment and evaluation, lessons learned, and recommendations are discussed in this paper.
New Methodology to Effectively Stimulate Water Disposal Wells Drilled in Acid Sensitive Sandstone formations in Saudi Arabia
Authors: Nasr-El-Din H. A. , Al-Habib N. S. , Zoraia G. H. , Nasser A. H. , Sunbul A. , Jemmali M.
Published: December 2007

Acid treatments for sandstones differ significantly from those for carbonate rocks. Unlike carbonate acidizing where HCl reacts with carbonates to generate reaction products soluble in water, sandstone acidizing using mud acids produces reaction products that may precipitate and reduce rock permeability. The challenges of sandstone acidizing are to optimize damage removal while minimizing formation-damaging precipitates.

Understanding formation mineralogy and the nature of damage is critical for designing a proper acid treatment. Sandstone acidizing has been always a challenging task, especially if the formation is acid-sensitive. Traditionally, sandstone reservoirs in the Northern Area of Saudi Arabia are not stimulated due to their negative reaction to acidizing.

Wells A and B were drilled and completed as vertical cased hole wastewater disposal wells for a refinery in the northern area of Saudi Arabia. They have been used to dispose the refinery wastewater since 1998. The injectivity of Well A was maintained since it was placed on injection, whereas well B showed low injectivity with a skin damage of + 20.

The major minerals found in the sandstone reservoir are quarts, dolomite, and calcite with kaolite and smectite. The latest analysis of the refinery injection wastewater showed that the wastewater contained suspended solids (iron sulfide) and oil. After several negative clean-up trials by flowing the well back in order to restore injectivity and maintain adequate wastewater disposal capacity of the refinery, it was decided to stimulate or sidetrack the well.

A new design methodology with extensive lab testing was applied to design a tailored treatment to address these challenges. It included a pre-flush of aromatic solvents, then stages of 10 wt% HCl, 9:1 HCl:HF acids. To achieve better acid diversion for the long perforated intervals (200 ft) with high permeability contrast, foamed diverter stages (quality 70%) were incorporated in the treatment.

A carefully designed train of treatment fluids was applied to remove formation damage induced by drilling and injection fluids. Injectivity tests before and after each step of the treatment was recorded and evaluated. Proper design and execution of the stimulation treatment almost doubled the well injectivity index from 47 to 86 b/d/psi. The maximum injection rate increased from 50 to 92 BPM, at 1,500 psi injection pressure. Challenges, fluid selection, design criteria, field treatment, lessons learned, and results of the acid treatments will be discussed in this paper.
Formation Evaluation and Remaining Oil Saturation Estimation with Pulse Neutron Logging Inside Tubing
Authors: Nacache R. , Saad I. , Guru U. , El Mahdy R.
Published: December 2007

Through-tubing carbon-oxygen (C/O) logging is a popular means for reservoir monitoring since a slim logging-inside-casing tool was introduced. The tools are available in 2.5 inch and 1.6875 inch outer diameters. Both the tools log inside of casing to quantitatively determine fluid saturation within the formation. In the absence of any other external information, the C/O technique has limitations when the survey is carried out inside the tubing. However, at times this becomes necessary when the reservoir to be evaluated is covered with both tubing and casing.

There has been limited use of the slim logging-inside-casing tool for completions with both tubing and casing. This application has augmented the C/O methods of saturation estimation for measurements made inside the tubing.

The present work documents the results of a pulse neutron logging operation carried out for estimation of the remaining oil saturation of a reservoir covered with tubing and casing. Both the inelastic capture and the sigma survey were recorded in this well. Careful planning was carried out for achieving an oil saturation precision of around 7 saturation units. The interpretation of the lithology from both the open and the cased hole logs is discussed. A new method was used for estimating the permeability from the cased hole spectroscopy logs. The saturation profile estimated from the C/O log is integrated with the estimated permeability results.

The saturation results are in agreement with field observations and also demonstrate that bypassed reserves can be estimated on the basis of pulse neutron logging carried out inside tubing.
Tuning EOS Using Molecular Thermodynamics to Construct Asphaltene Deposition Envelope (ADE)
Authors: Fahim M. A. , Andersen S. I.
Published: December 2007

The objective of this work to calculate ADE of asphaltene from molecular thermodynamics. Aphaltenes and resins are represented by pseudo-pure components, and all other components in a crude oil are presented by a continuous medium that affects attractions among asphaltene and resin molecules. Model parameters are evaluated systematically from average properties of asphaltenes and resins in crude oils, and from dispersion-force properties of the oil medium. Given the composition of the medium, and asphaltene and resin concentrations, the molecular-thermodynamic, calculated results for the effects of oil composition and pressure on asphaltene precipitation are in good agreement with experimental measurements for differentreservoir fluids, for several crude oils.The absolute average error was 9.8%
Novel Completion Technology Eliminates Formation Damage and Reduces Rig Time in Sand Control Applications
Authors: Garfield G. , Van Sickle E.
Published: December 2007

Formation damage caused by the perforating process is often found to be one of the leading contributors to poor productivity. Fractured and compacted zones, perforation gun debris, and broken formation blockages are common types of damage that can occur inside the perforation tunnel.

Reducing or eliminating initial perforation damage can result in a more productive well over its lifetime. This paper examines a completely new technology for completing wells in unconsolidated formations that eliminates explosive perforation discharges and its associated formation damage risk.

The new technology also provides a means for effective sand control while eliminating the need for conventional sand control processes. The tool system uses telescoping tubes that extend from the liner to the formation by hydraulic pressure and mechanical force. Once the tubes are extended (or telescoped), the liner is cemented in place. The tubes form a conduit from the formation to the casing ID and contain sand-control media which eliminate or restrict the flow of formation sand. This new completion method eliminates gravel packing and minimizes intervention in completion operations, saving substantial rig time. The system does not require large fluid-pumping treatments with high horsepower requirements, which simplifies operational logistics especially in remote or offshore environments.

Formation damage can also be caused by drilling mud and fluid-loss control measures after completion. This new perforating method eliminates both of these highly damaging mechanisms because the tubes extend out past the damage and into the formation, even in a washed out hole.

Application of the new technology will significantly reduce the cost of well construction by eliminating the need for perforating by allowing the production liner and primary cementing equipment to be run in a single trip with an effective means of sand control.

This paper describes initial field test results of the new system, cost comparisons with existing methods, and expected economic benefits over the lifetime of wells in typical applications of this new technology.
Economic Development of "Three Low" Oil Reserves
Authors: Chang Y. , Xu Q. , Tang W.
Published: December 2007

The effective development and utilization of the "Three Low" reserves will bring remarkable economic effects for oil companies. Since PetroChina's IPO, economic limits for development investments and operation costs in oilfield companies have been specified definitely to ensure high rate of return on investment and maximize shareholder's value. Within these limits, only high grade oil reserves with low cost per ton of oil can be produced normally while the "Three Low" reserves with high early investment and high operation cost can be produced hardly.

On the basis of study on the present status and future production trend of the "Three Low" reserves in PetroChina, this paper proposes following three view points through analysis and study on the existing economic provisions, operational modes and the existing national oil and gas laws, regulations and policies: first, production operator can take the advantage of the preference offered by the existing economic provisions in the "Economic Evaluation Methodology and Parameters for Petroleum Development Construction Projects" to reduce the early development investment and enhance the integral economic effects; second, by means of further flexible operation mechanism and amendment & completion of contract modes for cooperation, PetroChina will enhance the development extent of the "Three Low" reserves; Finally, the national macroscopic preferential policy for encouragement of rational development and utilization of the "Three Low" reserves will be proposed based on study on the national oil and gas laws and regulations, especially on the policy for oil and gas taxation.
Expanding Advanced Production Logging Operations to Short Radius Horizontal Wells
Authors: Kelder O. , Chatriwala S. A. , Ma S. , Al-Shammari F. , Fontanilla J. P. , Al-Towijri A. , Al-Shammari B. , Murray A. K. , Herz U.
Published: December 2007

This paper discusses the first successful coiled-tubing-conveyed production logging operation in a short radius horizontal well in Saudi Arabia. The production logging tool (Polaris[TM]) was modified with knuckle joints to pass through the severe well dogleg of 58 degrees per 100 ft in openhole. Subsequently, the tool was conveyed an additional 1400 ft in the horizontal section. The logging objective was to determine the flow profile for oil and water and identify the water entry points. The major challenge was tool deployment in this short radius well to gain access to the horizontal section. Monitoring of short radius horizontals has been almost nonexistent due to high dogleg severity. Because of the rigid tool length of conventional production logging systems, tool modifications were crucial and extensive job planning preceded the operations. Planning included modeling maximum rigid tool length, tool modifications, simulations for job feasibility with 1.75 in coiled tubing, and tool string bending moment tests. Prior to the main run, a dummy tool was successfully conveyed through the high dogleg to determine the feasibility of the operation. The successful completion of the log allowed the generation of a flow profile and identification of the major fluid entry poiints. These will help determine the most efficient way of sidetracking wells in the Ghawar Field to maximize reservoir sweep efficiency and to aid in planning future short radius horizontal wells.
A Case Study of a Successful Matrix Acid Stimulation Treatment in Horizontal Wells Using a New Diversion Surfactant in Saudi Arabia
Authors: Chatriwala S. A. , Al-Rufaie Y. , Nasr-El-Din H. A. , Altameimi Y. M. , Cawiezel K.
Published: December 2007

Matrix acidizing of horizontal and multi-lateral wells is a challenging taskfor several reasons. First, oil reservoirs are heterogonous in nature and thepresence of high permeability streaks is common. Proper diversion technique isalways required to better distribute the injected acid across the target zone.Secondly, stimulation of horizontal wells requires injection of large volumesof acids. This will require using an effective corrosion inhibitor package thatcan protect down hole tubulars and coiled tubing, especially in sourenvironments. Thirdly, recovering large volumes of spent acid is a concern,especially in tight formations. Acid treatments should be designed to addressthese issues in a cost effective way.

Currently, there are a limited number of chemicals that can divert the acidinto the formation. This paper introduces a new viscoelastic surfactant whichwas used to form stable foam during matrix stimulation of a seawater injector.The length of the target zone was 1,500 ft, and the average permeability of thecarbonate was 700 mD. A 1.75-inch coiled tubing was used to better distributethe acid in the open hole section (6.125-inch in diameter).

As with previous viscoelastic surfactant systems, the surfactant moleculesform structures in solution in the presence of salts. These structures enhancethe viscosity of solution significantly and can be broken by dilution withinjection water or by adding mutual solvent (3-5 vol%) to thepreflush/postflush stages.

Unlike previous viscoelastic surfactant-based systems, the new surfactantbuilds viscosity faster and its gel breaks down in a shorter period of time.

This paper examines the results of extensive lab testing that led to thedevelopment of this improved self diverting system. It will also give detailsof the first field application of this system. Following the acid treatment,the well injection rate improved by five folds, from 16,000 to 80,000 BPD.Benefits and improvements introduced by the new diversion technique will bediscussed in detail.
Successful Results Achieved by Applying New Sandstone Acidizing System in the Burgan Field: A Case History
Authors: Chakraborty P. K. , Al-Haddad S. , Jamal I. , Gizi N. H.
Published: December 2007

The Greater Burgan Field, located in southeastern Kuwait, covers about 320 sq miles of surface area and is classified as the largest clastic oil field in the world. The field produces mainly from cretaceous age sandstones of the Burgan, consisting of Third, Fourth and Wara formations.

The field was discovered on February 23, 1938, and production began eight years later. The Burgan formation holds most of the hydrocarbon reserves and accounts for approximately 90% of the field production.

Sandstone acidization offers major challenges to the petroleum industry, and previous treatments in this field did not reveal encouraging results. The application of recently introduced advanced fluids and engineering designs for sandstone acidizing has shown successful results. In addition to choosing the correct fluid system for the main acid treatment to avoid secondary precipitations, considerations for choice of appropriate type and correct volume of preflushes to condition the formation and use of proper overflushes proved essential.

This paper describes the application of a new sandstone acidizing system applied to a well completed in the Third Upper sandstone. This well had ceased to flow due to formation damage and was shut in for a long time. Core samples and reservoir rock properties were used to customize the acid system. The understanding of reservoir rock properties and the systematic approach of treatment design were key factors in employing this system. The system was tailored to penetrate deep into the formation while removing near wellbore damage.

Post-job production showed a significant gain from 0 to 949 BOPD of dry oil. To date, production has been sustained more than four years, adding value by saving the cost of repeated acid stimulation jobs and also by adding to the value of additional incremental oil gains.

The post-job analysis of results enabled further optimization of these processes, which would facilitate similar applications in many more wells in the region.
Using Integrated Project Models to Evaluate Field Development Options
Authors: Bilderbeck M. G. , Beck I. V.
Published: December 2007

This paper presents a practical and effective development concept evaluation and screening methodology that recognizes the fundamental relationship between reservoir potential and field development strategy.

A spreadsheet-based project modelling environment that integrates reservoir models and a field development planning model is described. The reservoir models account for uncertainty in reservoir performance. The field development planning model handles the scheduling and costing of wells and processing facilities. The use of uncertainty-based projections of reservoir performance to drive well and facility construction plans is illustrated.

The relative merits of adopting a multi-phase approach to the construction of facilities (to enable the opportunity to learn about a reservoir as a project matures), as opposed to a single-phase, up-front construction of facilities (to capture economies of scale), is discussed.

Lastly, the relative impact of uncertainty in the unit cost of wells and facilities, due to fluctuations in market demand for oilfield services, is examined.

To illustrate the benefits of this project modelling methodology, an example of its use is presented. The example consists of a large Middle East field in which further development is being considered, to increase production.
Live Oils Novel Organic Solid Deposition and Control Device: Wax Deposition Validation
Authors: Zougari M. , Hammami A. , Broze G. , Fuex N.
Published: December 2007

A novel laboratory-scale flow assurance tool termed "Organic Solids Deposition and Control (OSDC)" device has been developed to assess the potential and severity of organic solids deposition problems from hydrocarbon fluids at realistic production and/or transportation conditions. Based on optimized Taylor-Couette flow in concentric cylinder geometry, the OSDC mimics production conditions of temperature, pressure, composition, turbulence, shear, surface type and roughness.These key parameters can be accurately and independently controlled, allowing the deposition tests to be conducted over a wide range of conditions. Uniquely, this new device can simulate production system thermal-hydraulic conditions and produce fully developed turbulent flow for the live fluids and stock tank oils investigated.Heat transfer and fluid dynamics in the device were characterized through careful and detailed experimentation.Deposition tests performed on small volumes of live waxy crude oils resulted in the generation of reproducible wax deposits under consistent test conditions. The wax deposition rates were comparable to those from pilot-scale flow loops that utilized larger volume of fluid.
Review and Application of Short-Term Pressure Transient Testing of Wells
Authors: Soliman M. Y. , Azari M. , Ansah J. , Kabir C. S.
Published: December 2007

Short-term pressure transient testing is gaining increased acceptance as an attractive alternative to conventional transient well testing, since the latter usually requires long flow and shut-in periods in order to meet test objectives. Unfortunately, current industry drivers are focusing on short, cost-effective, and environmentally friendly test procedures _ especially in exploration wells in deepwater and arctic environments where conventional tests may be prohibitively expensive or not feasible logistically.

While various short-term tests, test procedures, and interpretation methods are available for conducting successful short-term tests, clarity is lacking for specific applications of these methods. Some of these tests include surge testing, closed-chamber testing, slug testing, underbalanced perforating and testing, and back-surge perforation cleaning. This paper provides comprehensive evaluation of general closed-chamber tests, including general surge tests, and their comparison with special tests such as, FasTest,™ Impulse™ test, and slug tests. For each of these techniques, the review will examine: Test design, testing procedureTheoretical background of each of these techniquesMethod of data analysis including comparisons based on both theoretical and practical considerations to determine the expected reliability, accuracy, and ease of analysis.

A large portion of the paper is devoted to field examples. Several field cases are analyzed using the various techniques, and results are tabulated and presented. Analyses of these examples are presented in significantly more detail to compare the many techniques available to analyze the well-testing data obtained from surge testing, closed-chamber DST, slug testing of oil wells, underbalanced perforating and testing, and back-surge perforation cleaning.
An Integrated RRT Prediction Method Combining Thin Sections, Sequence Stratigraphy and Logs
Authors: Chautru J. M. , Arab H. , Fujita N. , Pluchery E. , Poli E. , Shebl H. , El-Henshiri M. Y. , Shikama T.
Published: December 2007

This paper presents an integrated rock-typing workflow leading to enhanced 3D static models. The work is based on the integration of several tools which optimize the contribution of all the available data :

a specific thin-section description methodology sophisticated log-derived electrofacies calibration approaches, incorporating sequence stratigraphy rules; an enhanced calibration approach based on dynamic data.

It is illustrated by an application to the lower cretaceous carbonate reservoir in offshore Abu Dhabi.

The different steps of the methodology and their mutual interaction are detailed. This integrated work establishes a consistent way to fill the gap between core and production scales, using log-derived electrofacies extendable to all the logged wells. It is shown first how sequence stratigraphy can provide a global framework, common to the different scales that ensure the consistency of the whole work. Then, emphasis is put on the sophisticated thin-section description methodology, based on facies association identification and sequence stratigraphy, which facilitates the further electrofacies calibration. In a third step, we detail the log-derived electrofacies determination and calibration methodology, which takes into account thin-section description, core descriptions, sequence stratigraphy analysis, CCAL data, and SCAL data in order to provide consistent rock-types in uncored wells. In the end, it is shown how the integration of dynamic data in a well by well QC can significantly enhance the prediction of high permeability drains.

Modeling issues are then discussed, focus being put on the relationship between the various scales, on the geological control and robustness of the final 3D model that are enhanced by the large number of control points provided by the extension of rock-types to non-cored wells. The impact on dynamic modeling is shown as a conclusion.
On The Adjoint of a Nonlinear Diffusion-Convection Equation to Describe Flow in Porous Media
Authors: Vakili A. , Jansen J. D. , Esmaiel T. , Van Kruijsdijk C. P. J. W.
Published: December 2007

In this study Optimal Control Theory (OCT) was used to formulate the adjoint equation of a one-dimensional horizontal two-phase flow reservoir described by linear and nonlinear Diffusion-Convection Equations (DCEs). The use of tuning parameters allowed for a gradual transition between the linear and the nonlinear equations to determine the effect of nonlinearities on the solution of the adjoint equation. A numerical adjoint formulation was obtained from explicit and implicit finite difference discretizations of the linear and the nonlinear DCEs. A semi-analytical solution was obtained for the continuous adjoint of the linear DCE which served as a reference for analysis of some of the numerical results. Based on a simple example we found that for the linear model numerical dispersion did not affect the stability of the adjoint equation and that the resulting gradients remained stable. Explicit numerical implementation of the nonlinearities in the capillary pressure and fractional flow functions resulted in non-smooth (mildly oscillating) gradients of the objective function with respect to the controls for a number of time steps. A matrix stability analysis revealed the occasional occurrence of eigenvalues with magnitude one, indicating marginal stability, but no true instabilities were encountered. The observed oscillations in the gradients are not desirable for optimization purposes, since the resulting injection rates are fluctuating and the convergence of the optimization algorithm becomes difficult. However, the gradients became smoother for smaller time step sizes which suggests the need to use a smaller time step size for solving the adjoint equation than for solving the forward model.
Electrical Submersible Progressive Cavity Pump (ESPCP) Application in Kulin Horizontal Wells
Authors: Taufan M. , Adriansyah R. , Satriana D.
Published: December 2007

The original Kulin Horizontal well project scope was to drill two horizontal wells and run Electric Submersible Progressive Cavity Pumps (ESPCP's). ESPCP is a combination of Progressive Cavity Pump (PCP) and Electric Submersible Pump (ESP) motor as a down hole fluid lifting system and is ideal for use in horizontal wells. With rod less system, it will eliminate friction loss at tubing and rod. The PCP has more resistance to sand production and provides high efficiency production of viscous fluid. The Kulin Horizontal Drilling project started in early 2002 and ended in February 2003. The first horizontal well was Kulin 082 (KL082) and the second well was Kulin 083 (KL083). After the wells were completed using ESPCP as artificial lift, the initial production for KL082 was 708 BFPD, 531 BOPD, 25% water cut and KL083 was 518 BFPD, 394 BOPD, 24% water cut. The initial production was above estimated initial production of 300 BOPD/well.

The ESPCP's in both Kulin horizontal wells are installed in tangent sections with less than 2 °/100 ft build rate inside 9-5/8" production casing. The design threshold for ESPCPs is up to a maximum of 15°/100 ft build rate in the tangent section. The stator elastomer inside the PCP is operated at temperatures between 135°F and 150 °F and this is below the maximum temperature limitation for the elastomer. The flow rates, head and pump efficiency of the ESPCPs are controlled using surface mounted Variable Speed Drive (VSD).

As of June 2004, the ESPCPs that are installed in both Kulin horizontal wells have been operating for over 450 days and 800 days respectively without any mechanical problem from pump or ESP failures. Both ESPCPs was down in period mid of June’04 until early August’04 when the Kulin field was shut down due to facility safety issue.

The production rates from these horizontal wells are about 2.5–3.5 times greater than an average vertical producer in the field.

This paper will discuss ESPCP design, installation and performance in the Kulin Horizontal wells.
Minas Gas Compression and Liquid Handling Optimization Project
Authors: Ihwanto T. , Putra E. , Uditoyo S.
Published: December 2007

The gas compressor optimization project was established in late 2002. This project focused on gas processing and liquid handling to ensure reliable gas compressor operation and to secure condensate production. A cross-functional team was formed to perform comprehensive efforts to improve facility performance in dealing with field dynamic and to develop required action plans.

Since then, gas compressor unit reliability improves from 92 % in 2001 to 97 % in 2004. The improvement translates into flare rate reduction and operational cost savings. In the same time, condensate production shows improvement in term of quantity and quality. While sustaining the ongoing efforts, team presently works on look back to review results, lesson learnt and to identify new opportunities. This paper will describe the utilization of asset management process and executed efforts.
Production Optimization in ESP Completions Using Basic Intelligent-Well Technology
Authors: Vachon G. , Bussear T.
Published: December 2007

Of the various mechanisms that currently enable intelligent well systems, open/close remote-controlled sleeves and strain gauges are mature and less expensive than chokes and quartz gauges, yet they have many interesting applications when used in combination with Electric Submersible Pumps (ESPs). Though limited in functionality, they enable applications such as selective isolation of zones, as in the case of anticipated water breakthrough; fluid loss prevention when the ESP is turned off; or tandem ESP configurations for pump boost or redundancy. The lower costs of these tools make them economically attractive in many artificially lifted wells.
Impact of Off-Balance Fracturing on Borehole Stability and Casing Failure
Authors: Daneshy A. A.
Published: December 2007

Creation and presence of the hydraulic fracture can cause casing failure both during and after the fracturing operations. Although such failures are known to occur and have been a concern to many operators, the petroleum industry literature contains very little information on the subject.

During the fracturing operations, casing can fail under tension across the fractured interval either by de-threading of the collars or by tensile failure at perforations. The three main factors contributing to this failure are thermal shrinkage of the casing, off-balance fracture growth, and pseudo-openhole environment. Other contributing factors are borehole inclination with respect to the fracture plane, and the quality of the cement bond.

Factors contributing to casing failure during well production include changes in in-situ stresses due to reduction in reservoir pressure, off-balance fracture growth, formation layering and its inclination with respect to the wellbore, and shear strength of the interfaces. In particular, off-balance growth may create fractures that are not symmetrical with respect to the wellbore, and have different lengths in different layers. The resulting differential reservoir compaction induces shear stresses along the interfaces which can cause casing failure along the weakest interface.

The low formation shear strength along the propped fracture plane increases the probability of shear movement along it. Presence of the fracture will direct this movement towards the casing and can cause its shear failure. Rapid production pressure declines increase the shear stresses acting on the fracture plane and can cause movement along the fracture plane and casing failure.
Enhanced Oil Recovery in East Texas
Authors: Hyatt J. H. , Hutchison D. A.
Published: December 2007

This paper describes a working gas injection pilot that is demonstrating additional oil recovery from a very mature field.This small, low cost pilot has been very valuable in understanding and demonstrating commercial viability of this enhanced oil recovery (EOR) process before larger scale implementation.After nearly 70 years of water drive production, this immiscible gas injection process has enabled conversion from viscous displacement water drive to gravity stable, film drainage behind an advancing gas front.The design, implementation and current pilot results are discussed as well as the role of three dimensional (3-D) geocellular and flow simulation models.Current full-field implementation project design efforts based on pilot performance and learnings are also described.
Artificial Neural Network Model for Predicting Bottomhole Flowing Pressure in Vertical Multiphase Flow
Authors: Osman E. A. , Ayoub M. A. , Aggour M. A.
Published: December 2007

Accurate prediction of pressure drop in vertical multiphase flow is needed for effective design of tubing and optimum production strategies.Several correlations and mechanistic models have been developed since 1950.In addition to the limitations on the applicability of all existing correlations, they all fails to provide the desired accuracy of pressure drop predictions.The recently developed mechanistic models provided little improvements in pressure drop prediction over the empirical correlations.However, there is still a need to further improve the accuracy of prediction for a more effective and economical design of wells and better optimization of production operations.

This paper presents an Artificial Neural Network (ANN) model for prediction of the bottom-hole flowing pressure and consequently the pressure drop in vertical multiphase flow.The model was developed and tested using field data covering a wide range of variables.A total of 206 field data sets collected from Middle East fields; were used to develop the ANN model. These data sets were divided into training, cross validation and testing sets in the ratio of 3:1:1. The testing subset of data, which were not seen by the ANN model during the training phase, was used to test the prediction accuracy of the model and compare its performance against existing correlations and mechanistic models.The results showed that the present model significantly outperforms all existing methods and provides predictions with higher accuracy.This was verified in terms of highest correlation coefficient, lowest average absolute percent error, lowest standard deviation, lowest maximum error, and lowest root mean square error.A trend analysis was also conducted and showed that the present model provides the expected effects of the various physical parameters on pressure drop.
Spontaneous Imbibition Studies of Australian Reservoir Rocks With Neutron Radiography
Authors: Middleton M. F. , Murdoch U. , Li K. , de Beer F.
Published: December 2007

Spontaneous imbibition experiments were carried out on three core samples from the Mardie Greensand and one core sample of Barrow Group sandstone from the Australian North West Shelf. Water uptake into the samples, which were initially air-saturated, was measured by dynamic neutron radiography. The observed data were interpreted by (1) the linear diffusion-equation approximation for fluid flow and (2) the Li and Horne model. Both these models were consistent with the observed data, and have similar consequences. The linear diffusion-equation model suggests that a constant diffusion parameter, Dw, can adequately describe the observed spontaneous imbibition of water into these samples, under ambient temperature and pressure, throughout most of the imbibition process. The Li and Horne model suggests that (1) the effective water permeability of the sample and (2) water permeability times the capillary pressure gradient within the sample are approximately constant through most of the imbibition process, during these experiments. The combined conclusion of these interpretational methods implies that the water permeability and the capillary pressure-water saturation gradient in these samples are constant throughout most of the imbibition process, under ambient temperature and pressure conditions.
Dynamic Underbalanced Perforating on a Mature North Sea Field
Authors: Martin A. J. , Clark D. , Stirton G.
Published: December 2007

Dynamic underbalanced perforating1 is a technique for obtaining clean perforation tunnels resulting in much improved production or water injection. This technique has been successfully applied to several wells in the Ninian Field in the UK sector of the North Sea, resulting not only in better wells, but also in increased completion efficiency. In August 2003 a closed-chamber, dynamic underbalance shoot and pull operation was performed on Ninian North—a world first. The well came in at 50% higher production than expected. Since then, several other wells have been perforated using the same technique. Gauge data on the early wells showed the sequence of events, but did not capture the detail. A more recent well has been perforated using a new high-speed gauge that revealed the extent of dynamic underbalanced achieved. This paper describes the method, shows the results and discusses the value of using this technique.
Follow-Up Planning Tool for Material Planning, Delivery Management, and Stock Control in Well-Connection Material
Authors: Manuhoro P.
Published: December 2007

Total E&P Indonesie is one of the leading gas producers in Indonesia supplying more than 65% of the gas liquefied at the Bontang liquefaction plant. Operating 8 drilling rigs in all of their concession area, they drill an average of 150 wells within three years. This aggressive drilling activity is done to meet the natural gas delivery contract.
Estimating Formation Properties in Heterogeneous Reservoirs Using 3D Interval Pressure Transient Test and Geostatistical Data
Authors: Gok I. M. , Onur M. , Kuchuk F. J.
Published: December 2007

Proposal

The medium scale formation heterogeneity (about 1 foot to 100 feet near-wellbore) cannot be usually resolved well by conventional well test data, particularly in vertical direction. Spatial pressure data sets from the interval pressure transient testing (IPTT) along the wellbore measured by using multi-probe and dual packer-probe wireline formation testers (WFT) provide information about near-wellbore heterogeneity. The objective of this work is to examine the use of spatial 3D (three dimensional) IPTT data acquired by dual packer-probe WFTs and geostatistical information for estimating heterogeneous formation properties (e.g. horizontal and vertical permeability) in both lateral and vertical directions along the wellbore. There has been no systematic study in the literature about resolving heterogeneity in horizontal and vertical permeability and porosity from spatial 3D IPTT data. Throughout, formation property and parameter will be used interchangeably.

In this study, a 3D single-phase single-well (r-T-z) numerical flow model (simulator) was developed to simulate the behavior of IPTT measurements in heterogeneous media. Heterogeneity in formation properties is modeled at the gridblock scale by using geostatistics that allows properties to be treated as random regional variables with certain correlation structures. Horizontal and vertical property distributions conditional to IPTT data sets are estimated by using the inverse problem methodology based on Bayesian probability theorem. For estimation of formation parameters (properties) conditional to IPTT spatial data sets and geostatistical model, we minimize the objective function resulting from the application of the Bayesian probability theorem by using the well-known Levenberg-Marquardt (LM) algorithm. The sensitivity coefficients required in the LM algorithm are efficiently computed by using the adjoint method. We also show maps of sensitivity coefficients of packer interval and observation probe pressures with respect to parameter distributions (e.g., horizontal/vertical permeabilities and porosities) that offer important evidence about near-wellbore heterogeneities, where formation property distributions might be well resolved by interval pressure transient data.Synthetic examples are presented to show the methodology proposed in this work.
Visualization of Gravity Drainage in a Fractured System During Gas Injection Using Glass Micromodel
Authors: Dastyari A. , Bashukooh B. , Shariatpanahi S. F. , Haghighi M. , Sahimi M.
Published: December 2007

A main mechanism of oil production in naturally-fractured reservoirs is gravity drainage in the gas-invaded zone, where the pressure is below the saturation pressure and the matrix blocks are surrounded by the gas in the fractures. We investigated immiscible gas injection in a single-matrix block using a 2D glass-etched micromodel under the influence of gravity. Two different micromodels containing distinct patterns of the matrix-fracture system were constructed. The fractures were either parallel to the macroscopic flow or perpendicular to it. Extensive experiments on two-phase flow of oil and gas through the micromodels were carried out over a range of the capillary and Bond numbers. The displacement patterns were recorded by a camcorder equipped with a microscope. The images were then processed with an image processing software in order to estimate the initial and residual saturations of the two phases in each experiment. To study the effect of the fractures, we also performed the experiments in the same micromodels but without the fractures.

Our experiments indicate that the residual oil saturation is minimum in the case of natural depletion without gas injection, if the macroscopic flow is aligned with the gravity. However, when the system is inclined at 45 degree (relative to the direction of gravity), or when gas is injected into the system at different angles with respect to the direction of the gravity, the residual oil saturation is more than twice that of the natural depletion. The behavior of the displacement by gravity drainage of oil during gas injection is between two extreme limits of displacements. One is invasion percolation with trapping in which fractal displacement patterns develop, and significant trapping of the displaced fluid takes place. The other limit is similar to diffusion-limited aggregation in which there is no trapping at all, and the displacement pattern is a branched structure.