bluuebunny/crossref_metadata_2025 huggingface dataset:
Wellheads for an HP/HT Future
Authors: Hendrie C. F. B. , da Mota A. Carmona , Heijnen W. H. P. M.
Published: December 2007

The paper will examine the current shortcomings in wellhead technology in respect of the application of current designs for High Pressure/High Temperature (HP/HT) and Extreme HP/HT (X-HT/HP) projects now in the planning stages. An analysis will be made of the present qualification procedures required to achieve accreditation for wellhead products. Questions will be asked about the probity of the current test methods, which have been established by a self regulated committee consisting mainly of equipment suppliers. The paper will offer suggestions aimed at the mitigation of the risk of wellhead leakage, as our industry moves into ever more challenging and dangerous production environments.

The type of accident recently suffered offshore Egypt (under relative low pressure conditions) must be avoided on future HP/HT and X-HP/HT projects, as the potential consequences are too severe to contemplate. The paper will address not only wellhead design and qualification procedures, but it will also review safe installation practices, which eliminate the common practice of exposing unsealed casing annuli to the environment, at critical stages of the drilling of a well. This paper will seek to demonstrate that, particularly in HP/HT gas production environments, current conventional wellhead engineering and the associated qualification procedures cannot provide the technical solutions required to safely manage the risk of seal failure during field life.

It will be concluded that the movement between metal sealing parts as a result of pressure and temperature variations in the wellhead, have lead to failure after a limited number of cycles. It will further be concluded that in applications where the use of metal seals is critical to long term performance of wellheads, alternative technical solutions must be found which create rigid seal environments, to manage the risk of high pressure gas containment in wellheads.
Finding a Needle in a Rusty Hay Stack… Knowing Where to Start With 30,000km of Pipelines!
Authors: Petersen A. G. , Sivokon I. S. , Webster S. , Lane D.
Published: December 2007

TNK-BP plans to invest a significant amount of money in improving the integrity of its pipeline network over the next 5 years. The question that needed to be solved is where do we start? With a pipeline network that consists of over 43,000 individual lines that have a combined length of over 30,000 km selecting the right pipelines to replace, inspect and inhibit is not a trivial task. The task is made even more difficult when it is considered that when TNK-BP was formed it consisted of 600 legal entities, which did not have common processes and ways to store data. To address this problem a risk model was built which used data that could easily be collected for the pipelines in the company. After testing in the Volga-Urals and West Siberian regions the company then undertook a large data collection exercise. Using the risk model all pipelines have been ranked according to their probability and consequence of failure, and the data has been used to ensure that the investment in pipeline replacement, corrosion control and inspection are targeted to the areas where the biggest impact can be made. The exercise has also made it possible to understand how much investment may be required, because there is now a clear picture of the lengths of pipelines that have experienced failures. Pipeline prioritisation has answered the question where do we start, and is also helping us to answer the next question – when will we get there?
Evaluation of Activity Coefficient Models in Prediction of Wax Appearance Temperature
Authors: Ghanaei Ehsan , Esmaeilzadeh Feridun , Kaljahi Jamshid Fathi
Published: December 2007

In order to prevent wax formation phenomenon, it is essential to be able to predict the cloud point temperature by using a reliable thermodynamic model. The description of the solid phase non-ideality is the main obstacle in the modeling of the solid-liquid equilibrium of hydrocarbons.

In this work, 25 combinations of five models (regular solution theory, UNIFAC, predictive UNIQUAC, predictive Wilson and ideal solution model) for the description of solid and liquid phases have been surveyed to get the best results near the experimental data without using any adjustable parameters. For validating the models, ternary, quaternary and multi-component systems as the experimental data have been used.

The results show that for the C14-C15-C16 ternary and multi-component systems, the best models are predictive Wilson-regular solution and predicitve Wilson-predictive UNIQUAC, respectively, for the description of non-ideality behavior of solid and liquid phase. For the C18-C19-C20 ternary and quaternary systems the best models are predictive UNIQUAC-UNIFAC and predictive UNIQUAC-regular solution, respectively, for the description of solid and liquid phase behavior. These models, in comparison with multi-solid models, show better agreement with the experimental data.
Eliminating Additional Drilling Expense Due to Well Stability Problem in Laminated/Fractured Nahr Umr Shale Formation
Authors: Waragai Tatsuhiko , Yamamoto Koji , Tokuda Noriyuki
Published: December 2007

The wellbore stability problem of Nahr Umr (N.Umr) shale formation was the major drilling problem in an offshore field in UAE. The stability problem in the field was much severer than that in other offshore fields in UAE.

The stability problem had become worse since year 1997, when the usage of diesel in water-based drilling mud as a lubricant was prohibited for environment protection. To tackle the stability problem, mud weight was increased as the conventional method to avoid shale caving, which was successfully applied in the other fields. However, the problem could not be solved.

Accordingly, "Joint Study of N.Umr Shale Instability Problem" was commenced in year 2002. The historical review for actual drilling records since year 1991 was conducted to estimate the possible root cause of the stability problem. Intensive data acquisitions such as open hole logging and coring were performed, and the obtained data were used for chemical and mechanical analyses to recognize the nature of the N.Umr in the field. A geo-mechanical model was developed based on the analyses, and the mechanism of the stability problem was identified by simulations using the model. The following main findings were found out through the study;

The N.Umr shale in the field is laminated/fractured. The stability problem occurs due to the mud penetration into laminations/fractures, which causes the mechanical failure. Increasing mud weight is not a solution for the N.Umr in the field. Effective hole cleaning is another key factor, since the hole angle of the wells in the field is in most critical range for hole cleaning (30-50 deg.).

A new operation guideline was established based on the study results, and has been implemented since June 2004. No well sidetracking due to the stability problem has occurred after the implementation, while additional expenses were spent due to well sidetracking in years 1999-2003.

This paper describes the history of the shale stability problem in the field, the summary of the joint study, the new operation guideline and the actual operation results after its successful implementation.
Dynamic Production Optimization in Khafji Offshore Field
Authors: Ghoniem E. O. , Al-Khaldi M. A. , Samizo N. , Al-Thuwainy A.
Published: December 2007

The gas lift, by limited capacity of 25 MMSCF/D, was introduced for Khafji field in 1988 which could successfully sustain target rate until mid of 2004. Even though, additional artificial lift energy was planned as long term solution due to the increase of field water cut and depletion of reservoirs, production optimization was found to be the best way to sustain field target until commissioning of these new facilities. For that purpose, general optimization and gas lift allocation models have been built and applied for Khafji field as presented by Ghoniem et al1.

Although, production system modeling is a powerful technology to optimize and understand the whole production system, the individual well modeling hence dynamic nodal analysis and the reliable field measurements are still highly contributed to increasing oil rate. Consequently, the present work is a further and more comprehensive optimization study for Khafji crude production by:

Updating the previously built optimization models Screening for new effective wells for gas lift operation Review the design of existing gas lift installations Optimizing the choke size for many natural flow wells Practical adaptation to the dynamic process of production optimization.

As a result, several high productivity wells were selected and put recently on gas lift operations, also gas lift re-design was made for many wells. Furthermore, wellhead choke size was optimized for many natural flow wells. As a result, a significant marginal oil gain was obtained and confirmed by field measurements. Also, a lot of recommendations for gas lift operations and for mature oil fields were concluded.
Use of the NMR Diffusivity Log To Identify and Quantify Oil and Water in Carbonate Formations
Authors: Di Rosa D. , Gyllensten A. , Li W. , Georgi D. , Tauk R.
Published: December 2007

We report a successful example using the 2D NMR technique for determining oil-water contact (OWC) in difficult carbonate environments. We applied an NMR diffusion-based interpretation method to identify oil, water, and transition zones and to quantify the oil saturation in a limestone reservoir. Hydrocarbon typing and saturation determination from NMR logging usually require high contrasts of intrinsic or apparent relaxation times and/or diffusivity. Many carbonate reservoirs in the Middle East contain large-sized pores, which coupled with low relaxivity of carbonates results in long T1 and T2 times for water. Further, because light oil has a long relaxation time, there is little T2 contrast and small polarization contrast between water and oil. When these reservoirs contain very light or high-GOR oils, the diffusivity contrast between oil and water is also less pronounced. Hence, it is difficult to distinguish between the oil and water signal with most NMR hydrocarbon typing techniques. The example shows that a diffusion log reconstructed from 2D NMR interpretation works well even for marginal diffusion contrast cases. Furthermore, we present a modification to the Coates permeability model that is applicable to carbonate formations having partially connected vugs.
Restoring Well Integrity in a Critical Gas Pilot Injection Well
Authors: Al-Ashhab Jamal K. , Khan Naeem , Boyd Douglas
Published: December 2007

Appearance of abnormally high pressure in the 9 5/8" X 13 3/8" casing annulus of a pilot gas injection well located offshore Abu Dhabi, alerted staff to a potentially serious situation from both safety and economic viewpoints. The subject well is a critical component of a pilot project to test the effectiveness of gas injection towards improving oil recovery. Based on this and other data, decisions on long-term reservoir development involving considerable investment will be made. The well was drilled and completed in 1999 as dual gas injector into two, Lower Cretaceous limestone reservoirs and put under gas injection in 2001. Abnormally high pressure was observed in the 9 5/8" × 13 3/8" annulus after three months of injection. A multidisciplinary task force was formed with a mandate from senior management to locate the source of leaking gas, the communication path to surface and recommend remedial actions. A risk assessment ranked the danger to the 80 million U.S. dollar platform and personal as high. As a result, gas injection was halted and visits to the platform minimized. Evidence gathered from the well records and newly acquired diagnostic logs suggested the existence of poor or no cement behind the 7" liner and 9 5/8" casing providing a conduit for gas to surface. Moreover, the existence of two abandoned holes penetrating the shallowest reservoir and located at short distance from the currently active bore hole were recognized as potential pathways for gas to surface. Extensive remedial cementing operations were performed including: (1) block squeezes behind one and two sets of production casing above the source reservoir, (2) cement circulation squeeze between production and intermediate casings through mechanically drilled holes. The high annulus pressure was thought eliminated but soon returned after injection commenced. A decision was made to convert the nearby un-perforated Gas Observer to water injection for the shallowest reservoir and continue gas injection into the deepest reservoir of the original well.
Techniques Used to Monitor and Remove Strontium Sulfate Scale in UZ Producing Wells
Authors: Al-Ashhab Jamal , Al-Matar Hassouneh , Mokhtar Shahril
Published: December 2007

Scale deposition in completion strings is becoming a threatening problem to produce and safely operate wells completed in the Upper ZAKUM (UZ) oil field. Calcite or Calcium Carbonate (CaCO3) scale mostly found in the upper part of the production string, and Celestite or Strontium Sulphate (SrSO4) mostly found in the lower part of the production string, are the common type of scales encountered in Upper ZAKUM producing wells. Injection seawater (rich in Sulphate) and formation water (rich in Strontium ions) mix in the reservoir and/or wellbore under varying conditions resulting into Strontium Sulfate Scale formation in downhole equipment. While CaCO3 scales are possible to be removed by the use of common acids and wireline tools, Strontium Sulphate scale requires special techniques to remove chemically and/or mechanically, and present the most challenges to achieve complete removal.

This work will describe ZADCO scale management strategy to monitor and remove Strontium Sulfate scale in Upper Zakum producing wells. A scale prediction simulator is used to identify wells with high scaling risk. Scale Risk Matrix (SRM) is being developed to classify the scale risk in each well. The Chlorides content, the percentage sea water in the produced water, the production rate, the percentage water cut and scaling index are the main parameters that are used to calculate the overall scaling risk for a certain string. The wells classified as high scaling risk wells, are included on a monitoring list for periodical scale checks by running gauge cutters on slickline. Scale samples are collected and sent to the lab for analysis and scale type identification.

The category of strings with a scale thickness less than 0.25" are treated with a chemical scale dissolver, the wells containing scale thicker than 0.25" are treated with downhole cleaning tools run on Coiled Tubing.

In 2005, ten wells severely scaled with Strontium Sulphate were mechanically treated using Coiled Tubing, Mills and motor, high pressure rotating tool with Sterling Beads* and Polymer as the cleaning fluid. Most of the job objectives were not completely accomplished due to severe hard scaling conditions.
Competency Management: Value, Approaches, and Challenges
Authors: Brett J. F. , Salah M. G. , Lilly Larry L.
Published: December 2007

In the upstream petroleum industry, what is the true economic value of developing and managing the individual competencies of technical professionals? This paper uses two approaches to value competency development. The first uses historical data to assess the impact of the competency shortage during the 1980's boom and compare its net effect with what we might expect over the next few years. The second method builds a formal competency development business case using full-cycle economics. Both of these analyses indicate that competency management is likely to be financially beneficial in the near future— possibly up to 20% of total E&P expenditures. The paper then describes approaches to reliably manage competencies and outlines several challenges with each approach.
Evolution of Gas Bubbles From Offshore Wells
Authors: Emenike C. O. , Afghoul Ali Chareuf , El Mzien Nabil , Latifi Laid
Published: December 2007

In year 2002, gas bubbles from seabed were observed around well casing at some of Upper Zakum platforms.

During the investigations of this phenomenon it was noticed that the gas from the annuli (tubing X 9 5/8" casing and 9 5/8" casing X 13 3/8" casing) was having high hydrogen content. Concern was raised when the hydrogen content of the analyzed gases was as high as 99%.

In view of the potential risk to operators posed by this high concentration of this highly inflammable gas (H2), a multi - disciplinary team was established to investigate the source of hydrogen and subsequently to develop measures to protect the environment, personnel and ZADCO assets. The taskforce was also asked to produce an operational guideline to safely operate and work in such an atmosphere. Subsequently, chemical thermodynamics and kinetics / mass transfer models were used to identify sources of hydrogen and subsequent transfer of hydrogen from sources to the annuli. Eventually these theoretical analyses were reconciled with tubular inspection findings. These and other factors are discussed in the paper.
Reliability of Cement Bond Log Interpretations Compared to Physical Communication Tests Between Formations
Authors: Boyd Douglas , Al-Kubti Salah , Khedr Osama Hamdy , Khan Naeem , Al-Nayadi Kholoud , Degouy Didier , Elkadi Antoine , Al Kindi Zaid
Published: December 2007

Two classes (sonic and ultrasonic) of cement bond log tools are run in tandem as part of ZADCO's standard cement evaluation program. The effectiveness of these tools and their evaluations are often challenged and are not regarded as a replacement for reservoir inter-zonal communication tests performed between producing reservoirs on every well. Consequently the value of continuing to run these tools was raised by management. In response, the reliability of these tools and their interpretations for determining the existence of poor behind casing cement quality and possibly hydraulically communicating layers was critically and systematically examined by a dedicated team of ZADCO and Schlumberger technical professionals. The criteria used to judge the usefulness of these logs was the present or not of communication behind casing as determined by the physical test. For the twenty-eight wells examined, twenty-five of the cement log interpretations matched the communication test results. One well which communicated had 10 feet of apparent good cement with the remainder poor. Its cement log suffered from eccentralization which negatively affected the cement bond log interpretation. Two wells with long intervals of excellent cement on logs suffered behind casing communication. The reasons for this remain unresolved but are a source of constant discussion. Possible explanations for the mismatch between cement evaluation log interpretation and the physical test results are explored.
Producing Dry Oil From a Transition Zone: Should This Be Called a Wedge Zone?
Authors: Efnik Mohamed Saleh , Hafez Hafez , Haajizadeh Masoud , Hamawi Mohamed , Al-Mansori Maisoon , Kenawy Maher , Abdulla Faisal
Published: December 2007

There is a common mis-understanding about the transition zone in which both water and oil should be mobile.

This paper will illustrate that in the transition zone only oil is movable above the Free Water Level (FWL) at normal gravity conditions. Putting wells on production in the transition zone produce dry oil unless the drawdown pressure disturbs the normal gravity conditions.

To avoid any confusion among geoscientists and reservoir engineers, we introduce new term called the "Wedge Zone", where the water saturation increases down flank towards the oil-water contact as a result of gradual increase in the micropores with bounded water due to diagenesis and cementation. The intensity of the diagenesis (cementation) is related to the timing of oil migration and entrapment.

Four wells that had been drilled in an onshore field in the Middle East in the Wedge Zone and have producing dry oil for the last two years. As result of repositioning the new wells based on the Wedge Zone concept, an extra amount of recoverable oil will be added.

The Modeling techniques over this zone have been revised resulting in changing the concept of modeling the transition Zone to that modeling of a Wedge Zone. As a consequence, the model prediction of sweep efficiency is also impacted.
An Approach for Production Enhancement Opportunities in a Brownfield Redevelopment Plan
Authors: Cuauro Antonio , Ali Mohd Izat , Jadid Maharon Bin , Kasap Ekrem , Friedel Torsten
Published: December 2007

Betty is an oil field discovered in 1968 and produced since 1978. With the objective of rejuvenating the asset, a multidisciplinary optimization team was built. The standard practices for production enhancement opportunities include logging, nodal analysis and well engineering technologies. Usually, the older the field, the more challenging to achieve additional reserves. This paper outlines an integrated approach for achieving these opportunities, reducing the risk on oil recovery associated with the various enhancement initiatives. The objectives of this paper are to present (i) how using numerical simulation to support and improve the strategies for production enhancement opportunities identified by the standard screening exercises in a brown field and (ii) how to optimize redevelopment plan for maximum recovery.

First, several increased well production opportunities were identified based on the standard methodology. Then, to reduce uncertainties and risks associated with proposed activities, full field numerical simulation model was run and results were reconciled. This was followed by incorporation of the surface facility constraints to identify bottlenecks. The comparison between standard analysis and the new approach gave a more reliable platform for predicting field performance. Results also added valued information for optimizing further infill drilling targets. Lessons learned and recommendations for future development campaigns on other fields were established.

After 6 months of implementation and monitoring, the proposed initiatives have achieved some 13% increase in the total oil production; savings 14 MMUS$ by reducing the number of infill wells planned, and creating an additional ultimate oil recovery of 4.98 MMstb. In the future, implementation of all opportunities will produce sufficient information for optimizing infill drilling and work-over campaigns on Betty Field.

The application of this innovative approach to brownfields helped identifying new opportunities, which have been a key factor in the rejuvenating Betty Field.
ADCO ESP Pilot
Authors: Hashim Hafsa A.
Published: December 2007

In one of ADCO's mature fields several horizontal oil wells have ceased to flow due to the high water cut. In order to accelerate data acquisition on well, reservoir and ESP performance at these higher water cuts, an ESP pilot project was performed in three wells.

ADCO's past experience with ESPs in some of the main fields in deep, high temperature and GOR wells (250 deg F and 700 scf/bbl, respectively) has been poor and discouraging. To ensure that future ESP applications in these fields are successful, a comprehensive review was conducted by ADCO and industrial shareholders (ISH) to determine the root causes of the previous failures and recommend methods to improve current practices.

In accordance with the recommendations, a multidisciplinary team was set up to plan and execute the ESP pilot project. The project team was responsible for the tendering, designing and engineering aspects, gathering the reservoir data, finalizing the completion strategy, equipment sizing, installation, commissioning and monitoring.

The result of this effort was the successful installation and running of ESPs in two of the field's oil wells. The project success is of paramount importance as it can lead the way for future ESP applications in similar harsh downhole conditions.

This paper discusses ADCO's approach to overcome the past difficulties it had in running ESPs in deep and hot oil wells starting from the review up to the installation and commissioning.
Unique Expandable Sand Screen and Expandable Liner Hanger Completion for Saudi Aramco
Authors: Al-Baggal Zaki A. , Refai Ibrahim , Abbott James W.
Published: December 2007

This paper discusses the first well in which an expandable screen and expandable liner hanger were installed in a horizontal openhole well for Saudi Aramco. Wells in this area require sand control; however, alternative sand control solutions presented some potential problems in the Saudi Aramco wells. Supporting the borehole by packing the annulus space with gravel to prevent pockets in the screen/openhole annulus is a viable solution in some sand control environments; however, Saudi Aramco decided to investigate an expandable sand screen that has an expandable steel base pipe designed to protect the wellbore from collapse and maintain screen integrity. This screen design is considered to be the strongest in the market, with 2,500 psi collapse strength. The screen is run inside the open hole, and after expansion, the screen extends to an outer diameter that is equal to the openhole inner diameter.

The case history data will include the completion design process and a description of the successful deployment of 1,310 feet of the expandable screen into the horizontal lateral. Before expanding, the screen O.D. was 5-3/8-in, and after expansion, it had enlarged to the open hole ID of 6-1/8-in. This expandable deployment is significant as it was not only the first application of expandable, rigid, perforated base-pipe screen in the Middle East, but it was also the longest deployed to date for this type of 6-1/8-in. expandable screen worldwide. This application was also the first completion in which an expandable liner hanger was used in the same well as an expandable screen in the Middle East.

The well has been put on production and has shown excellent productivity as well as sand control.
Field Development Plan by Optioneering Process Sensitive to Reservoir and Operational Constraints and Uncertainties
Authors: Kasap E. , Sanza G. J. , Ali M. I. , Friedel T. , Waheed A. , Sukmana A. Y. , Cuauro A. , Cabrera C. , Rasol M. N. B.
Published: December 2007

A revised Field Development Plan (FDP) for Betty Field was prepared based on a process that was simultaneously sensitive to reservoir and operational constraints and uncertainties. This so called "Optioneering" process was an iterative, multidisciplinary optimization task that generated an action plan based on multiple options developed by reservoir, production, drilling and facilities engineering and ranked by economics. The process specifically involved first generating a series of unconstrained production options, which then considered drilling reach and anti-collision limitations, and finally had the appropriate facilities and regional evacuation constraints imposed. To achieve this, history-matched numerical reservoir models were first run within the framework of an infill well-location optimization software package. Then, drilling constraints were imposed with drilling planning software and facility constraints were included via a surface coupling system for multiple-reservoir models. Uncertainties in the reservoir characteristics and in the facilities/evacuation schemes were addressed by quantifying their impact on the ultimate recovery efficiency.

During the optioneering exercise, more than 100 unconstrained options for seventeen stacked reservoirs were identified from the perspective of infill drilling, pressure maintenance by gas injection and/or waterflooding, high pressure gas production, horizontal wells and production enhancement work. Based on typical costs and economic rank, the high potential unconstrained production options for each reservoir were determined. After imposing the drilling constraints, all reservoirs were then coupled to account for surface facility constraints. In the final analysis, five sidetrack wells reaching 12 new drainage points (NDP) over 10 reservoirs were designed. This infill drilling scheme will increase current reserves by 128%. Furthermore, a gas injection scheme identified as the optimum plan for A6.0 reservoir will increase current reserves by 28%. Field wide recovery factor will be improved by 9%.
Quantification of Fracture Permeability From Micro Resistivity Logs in Offshore Abu Dhabi Reservoir
Authors: Al-Farisi Omar , Elhami Mohamed , Barkawi Abdul Naser , Al-Marzouqi Mariam , Al-Jefri Ghassan , Kadada Talal
Published: December 2007

In Abu Dhabi offshore carbonates, it is recognized that fractures play an important role in influencing reservoir flow and connectivity both vertically (between reservoir units) and areally within the same reservoir unit. Image logs and borehole seismic surveys have been run to extensively identify fracture location and direction to understand the flow path of these reservoirs. However, in this paper an advanced step has been achieved in quantifying the fracture permeability from Conventional Logging Data, which is Micro-Resistivity Log, aided with Gamma-ray and Neutron-Density porosity logs. We all realized how vital, useful and critical this type of information would be as an input to reservoir simulators. This paper presents two techniques that have been developed to determine fracture permeability in reservoir rock and dense zones, these two techniques are merged to call it UFLIP (Universal Fracture Log Integrated Permeability).

The First technique is applicable for Reservoir Zones, it utilizes micro-resistivity logs as an invasion profile tool, and then by calculating Universal Rock Permeability (UROK)1, it establishes the permeability information due to invasion. It is then compared with a matrix driven permeability estimator that utilizes GR in technique called (PASZ - Permeability Active Searching) - same reference above-. The difference between these two permeability estimators indicates and produces the existence of fractures in reservoir rock and fracture permeability value.

The Second Technique utilizes UROK permeability value in addition to porosity and permeability thresholds to identify fracture permeability in Dense Zones between reservoir, as this zone is very vital the critical to production communication between reservoirs and hence production performance.

A great deal of multi-disciplinary effort is necessary to generate and validate this data for both techniques and is reflected in the extensive use of image logs and well-test-profile analysis as quality checks and correlation tools. Additional benefit is seen from this technique in having the ability to get real time fracture permeability data that helps reservoir and petroleum engineers in designing completion for optimum production.
Synthesis of Experience in Supporting Hydraulic Fracturing Treatments Using Cross-Dipole Acoustic Log
Authors: Sadykov M. R. , Pasynkov A. G. , Nikitin A. N. , Stenin V. P. , Metlin V. V. , Dobrynin S. V.
Published: December 2007

The only way to increase the reasonableness of candidate well selection for hydraulic fracturing treatment, as well as to optimize the technology of implementation of this production enhancement method is trough achieving a new level of information support for the preparatory stage of these operations.

As one of the types of studies to significantly facilitate generation of hydrodynamic models, the multi-array multi-wave polarized acoustic log may serve, which makes it possible to optimally compute the fracture design and to predict the direction of fracture propagation before performing the fracturing treatment, and to evaluate the actual geometry of hydraulically induced fracture with maximum reliability.
Fracture Analysis for Carbonate Reservoirs Using 3D Seismic P-Wave Data: Middle East Case Study
Authors: Wang David Y. , Lu Chih-Ping , Dong Wenjie , Johns Mary K. , DeGraff James M. , Anderson James H.
Published: December 2007

Seismic reflection amplitude at the top of a fractured rock layer varies as a function of both offset and azimuth. Travel time and attenuation along ray paths through a fractured layer also vary with offset and azimuth. An integrated set of procedures and a flexible workflow were developed to extract these measures of azimuthal seismic anisotropy. The procedures include screening tools to evaluate the feasibility of applying seismic inversion methods to extract azimuthal attributes, and quick-look tools to rapidly visualize seismic anisotropy that may indicate open fractures.

Azimuthal anisotropy is recognized in seismic data from a giant Middle East oil field by identifying differences between sector stacks formed from different azimuth bins. This screening analysis shows an azimuthal AVO response that seems to vary in a meaningful way across the field. Further analysis utilized a proprietary, azimuthal AVO, inversion process that estimates two attributes. The first quantifies AVO anisotropy that may be related to fracture intensity, differential stress, significant stratal dips, or other factors. The second attribute is related to fracture orientation when fractures are the cause of anomalies. A goodness-of-fit estimate quantifies the error between the fitting function and the observed data. Inversion results show areas with strong azimuthal variations that correspond well with coherent energy observed in the sector stack difference, but with improved spatial resolution and contrast.

The key to using azimuthal seismic anomalies wisely in reservoir development is their integration with subsurface data to discriminate among possible sources of the anomalies. The validation phase of the study used subsurface data on fracture intensity, in-situ stress state, stratal geometry, erosion surfaces, and production data and tests. Maps of seismic anisotropy show coherent anomalies related to known geologic features, giving confidence that the method detects meaningful geologic information that can be used to constrain reservoir quality models.
Comparative Study of Flowback Analysis Using Polymer Concentrations and Fracturing Fluid Tracer Methods: A Field Study
Authors: Asadi Mahmoud , Woodroof Robert A. , Himes Ron E.
Published: December 2007

This paper compares flowback efficiencies using polymer concentration and frac fluid tracer methods. Results are presented for the flowback efficiency of each frac fluid segment using non-radioactive chemical frac tracers injected in a well as well as the results for the total flowback efficiencies using polymer concentration and frac fluid trace analysis methods. Two wells were fraced and traced with various chemical frac tracers. Upon commencing flowback, samples of produced aqueous solution were collected according to a pre-designed sampling schedule that lasted for 72 hours. Samples were analyzed for tracer, polymer, calcium, potassium, sodium, and chlorine concentrations. With the use of the mass balance technique, the total flowback volume and flowback efficiency for each fluid segment were calculated using the tracer method. In addition, total flowback and flowback efficiency were calculated using both polymer concentration and tracer methods. To better evaluate and compare the results of polymer concentration and frac fluid tracer analyses, dynamic fluid leakoff tests were conducted in a laboratory environment using both low and high permeability core samples. Detailed laboratory and field results are presented along with comparison of flowback results from both polymer concentration and frac fluid tracer methods.
Reactive Transport Modeling of Carbonate and Siliciclastic Diagenesis and Reservoir Quality Prediction
Authors: Xiao Yitian , Jones G. D.
Published: December 2007

A fundamental challenge in reservoir characterization is the accurate prediction of diagenesis on reservoir quality and heterogeneity. Reactive transport modeling is an emerging technology that can be used to simulate coupled multi-phase fluid flow and diagenetic reactions. It has the unique capability to predict spatial and temporal variations in porosity and permeability and reservoir quality evolution at both geological and production timescales. We applied reactive transport modeling to investigate several styles of diagenesis in both carbonate and siliciclastic rocks: 1) Early diagenesis in a freshwater lens and associated hydrological zones in an isolated carbonate platform; 2) Dolomitization and anhydrite cementation in a brine reflux system; 3) Geothermal convection and burial diagenesis in a salt buried isolated platform; 4) Fault induced hydrothermal fluid flow and illitization; and 5) Formation alteration associated with steam (water) and acid injection and artificial diagenesis. Adopting a sensitivity analysis approach, we examined how key natural variables, such as climate, sea level, temperature, salinity and fluid composition and porosity/permeability heterogeneity impact different styles of diagenesis and reservoir evolution. We also examined how formation damage caused by artificial diagenesis in production can be predicted by reactive transport modeling. Linking fundamental geochemical processes to predict reservoir quality has significantly improved our understanding of several conceptual diagenetic models and paradigms. Our novel approach suggests that reactive transport models, when sufficiently integrated with traditional methods and calibrated with field data, have the potential to significantly improve our ability to predict carbonate and siliciclastic reservoir quality.
Downdip Oil Potential for an Onshore Abu Dhabi Petroleum System
Authors: Pottorf R. J. , Hussenoeder K. L. , Tseng H. , Petersen K. , Davis C. L. , Richardson M. , Pietraszek-Mattner S. , Moore D. W. , El Agrab A. F. , Khouri A. A.
Published: December 2007

A combination of fluid inclusion and geochemical analyses were conducted on rocks and reservoir fluids to develop an improved understanding of down-dip oil potential in a mature exploration play, onshore Abu Dhabi. Exploration for oil in the region is complicated by low permeability carbonate reservoirs, poor seismic imaging, and complex hydrocarbon maturation and migration histories. In addition, a broad range of fluid properties, including gas, condensate, and high API oil make evaluation of reservoir fluid phase difficult to evaluate.

In this challenging environment, geochemical and fluid inclusion techniques are effective tools for identifying down-dip oil potential from gas cap fluids and reservoir rock samples. Fluid inclusion data are used to develop a hydrocarbon emplacement history, which constrains the distribution of fluids throughout the exploration area. In some areas, under-saturated gas inclusions trapped at present-day temperatures suggest a high risk for down-dip oil. Conversely, other structures contain oil inclusions that have been displaced recently by saturated gas, suggesting good potential for down-dip oil. Geochemical analyses of recovered fluids were independently utilized to predict the likelihood of down-dip oil. These combined techniques were placed in a geologic framework to regionally risk the potential for down-dip oil throughout the exploration area. This allows for improved resource evaluation and prioritization of exploration efforts in areas of the play where a high probability of down-dip oil exists.
New Hybrid Steam-Solvent Processes for the Recovery of Heavy Oil and Bitumen
Authors: Nasr T. N. , Ayodele O. R.
Published: December 2007

Canada has declining reserves of conventional oil, but vast reserves of heavy oil and bitumen. Over 90% of the world's heavy oil and bitumen trapped in sandstones and carbonates are deposited in Canada and Venezuela. Up to 80% of estimated reserves could be recovered by in-situ thermal operation. The current in-situ thermal technologies such as cyclic steam stimulation (CSS), steam flooding and steam-assisted gravity drainage (SAGD) are energy intensive and use large quantities of fresh water. Increasing pressure of environmental concerns and the threat of a carbon tax will make it imperative to find new oil extraction technologies that are less energy intensive and that use less water. Combining technologies in the form of hybrid steam-solvent processes offer the potential of higher oil rates and recoveries, but at less energy and water consumption than processes such as SAGD.

At the Alberta Research Council, new hybrid steam-solvent processes have been undergoing development in recent years. The Expanding Solvent-SAGD (ES-SAGD)(1–2), is aimed at improving and extending SAGD performance by solvent addition to steam. The improvements include higher and faster drainage rates, lower energy and water requirements and reduced green house gas (GHG) emissions. The Thermal Solvent Hydrid process focuses on combining solvent with a small amount of steam in a VAPEX (vapour extraction) process(3–4). This process offers the potential of higher rates than cold solvent VAPEX at less energy consumption than SAGD.

Hybrid steam-solvent processes, when fully developed, will extract oil at lower cost than SAGD and will also open currently marginal resources for exploitation, increasing oil reserves. This paper presents and discusses the principal concepts and key parameters for the new hybrid steam-solvent processes and compares expected performance to SAGD.
Simulation of Microbial Enhanced Oil Recovery
Authors: Ghadimi M. R. , Ardjmand M.
Published: December 2007

Nowadays, the experts in biotechnology and oil engineering cooperate to improve the production of oil reservoirs. A large portion of the world energy consists of non-renewable fossilized fuels; the primitive methods in oil recovery just make 8 to 30 percent of oil reservoirs available. So, the owners of these reservoirs are trying to increase efficiency via using newer methods with lower costs. One of the most important new methods in oil recovery enhancement is the microbial method (MEOR), which is based on utilizing special microbes to increase the production of oil wells. In this project a computer software is presented for simulation of microbial enhanced oil recovery. In other words, an oil reservoir is simulated for applying microbial method.

Firstly mass balance equations of reservoir fluid (water & oil), bacterium, metabolite and nutrient are droved and analyzed considering the experimental data and mathematical relations of a MEOR model. This information is applied on one of the oil reservoirs in Persian Gulf. The equations are simulated by applying numerical methods (finite element, successive overrelaxatoin) using a computer software (MATLAB). The effectively of application by this method for enhancement of oil recovery is assessed through analyzing the graphs resulted from this software which includes the profiles of concentration (water, oil, bacterium, metabolite and nutrient), pressure and also plots of oil and water saturation, mobility of water and oil. The obtained results show that through applying this method, pressure of reservoir that is the main factor will increase linearly leading to enhanced oil recovery from reservoir.

Furthermore, this method can be used as a pattern in analyzing other reservoirs in which MEOR is used for enhanced oil recovery.
Simulation Of Microbial Enhanced Oil Recovery
Authors: Gheshlaghi M. R. Ghadimi , Ardjmand M.
Published: December 2007

Nowadays, the experts in biotechnology and oil engineering cooperate to improve the production of oil reservoirs. A large portion of the world energy consists of non-renewable fossilized fuels; the primitive methods in oil recovery just make 8 to 30 percent of oil reservoirs available. So, the owners of these reservoirs are trying to increase efficiency via using newer methods with lower costs. One of the most important new methods in oil recovery enhancement is the microbial method (MEOR), which is based on utilizing special microbes to increase the production of oil wells. In this project a computer software is presented for simulation of microbial enhanced oil recovery. In other words, an oil reservoir is simulated for applying microbial method.

Firstly, mass balance equations of reservoir fluid (water & oil), bacterium, metabolite and nutrient are droved and analyzed considering the experimental data and mathematical relations of a MEOR model. This information is applied on one of the oil reservoirs in Persian Gulf. The equations are simulated by applying numerical methods (finite element, successive overrelaxatoin) using a computer software (MATLAB). The effectivity of application by this method for enhancement of oil recovery is assessed through analyzing the graphs resulted from this software which includes the profiles of concentration (water, oil, bacterium, metabolite and nutrient), pressure and also plots of oil and water saturation, mobility of water and oil. The obtained results show that through applying this method, pressure of reservoir that is the main factor will increase linearly leading to enhanced oil recovery from reservoir.

Furthermore, this method can be used as a pattern in analyzing other reservoirs in which MEOR is used for enhanced oil recovery.
Enhanced Prediction of Wellbore Stability Using Seismic-Based Geomechanical Modeling
Authors: Zinchenko I. , Moiseev Yu. , Garagash I. , Baransky N. , Smirnov K. , Kozlov E.
Published: December 2007

The set of geologic medium parameters controlling wellbore stability includes minimum and maximum horizontal stresses, pore and fracture pressure, and intensity of natural fracturing. In this paper, we demonstrate the use of 3D seismic data for mapping these parameters related to certain depth interval. In our approach, the transfer from seismic data to the set of parameters above is carried out using geomechanical modeling. In contrast to routine techniques stemming from elastic Earth model, the mechanical model we use is based on the poroelastic Biot's theory for saturated porous rocks with elements of plasticity included to predict pore pressure and fracture pressure. Respectively, in addition to seismic velocity, the input data for the modeling includes a series of petrophysical and mechanical properties such as the rock density, porosity, permeability, the Poisson ratio, rock cohesiveness, angle of internal friction, and sometimes, the dilatancy angle.

The combined use of seismic and petrophysical data provides for a more accurate prediction of stresses, pressures and fracturing as compared to traditional approaches. Hence, a more accurate conclusion on the expected stability of a wellbore with a particular trajectory at each particular site and each particular depth interval can be derived from the modeling results.