bluuebunny/crossref_metadata_2025 huggingface dataset:
Innovative Technique to Prevent Post-Fracturing Water Production using Relative Permeability Modifiers
Authors: Ali Ahmed , Amer Mohamed , Yassine Rami , Abdel-Khalek Tamer , Hamdy Ahmed
Published: September 2011

Hydraulic fracturing has been used for a long time in the Egyptian western-desert reservoirs and has proven to be very beneficial in increasing well productivity by approximately 25% over that of wells completed without hydraulic fracturing. However, production of water caused by fracture growth into the adjacent underlying (or overlying) water zones to the hydrocarbon zone is a major challenge.

Excessive water production threatens the economics of a well by Shortening its production life by trapping the hydrocarbon reservesIncreasing disposal and lifting costs that can reach up to an estimate of billions of dollars, partially attributed to water-disposal regulationsBoosting fines-migration problemsIncreasing the rate of tubular corrosion and scale buildup

These can be sufficient reasons to not consider fracturing in marginal fields.

The conformance-while-fracturing (CWF) technique incorporates a relative permeability modifier (RPM) in the fracturing-fluids design. The RPM provides a reduction in effective permeability to water without significant changes to the relative permeability to oil. Applying the CWF technique resulted in water cut as low as 4%, even when the adjacent water zones were within 10 ft of the perforations. This technique provides a tremendous economic boost and has been found to be an effective solution for fields otherwise plagued with water production. Increased recoverable reserves are now being observed from these wells. This paper discusses the geological and reservoir parameters of the wells and zones of interest, the properties of the RPM, the CWF job-design considerations (and the associated challenges to the job design), its field applications, and post-fracturing results in comparison to offset wells fractured conventionally in the same reservoir and at the same level. It is envisaged that CWF techniques will prove to be beneficial to other operators facing similar production challenges.
Mitigating Compaction Damage Through Real-Time Strain Monitoring at the Sandface
Authors: Earles Denise M. , Stoesz Carl W. , Pearce Jeremy G. , DeJongh Hans A.
Published: September 2011

Subsurface geo-mechanical stresses can cause formation faults, slippage, and compaction. These movements result in well failures, impacting production and resulting in significant expense and lost revenue. Traditional means for detecting such failures are limited and usually require interrupting production to re-enter the well, resulting in late detection of the problem and limited counteractive options.

A fiber optic support device has been developed to permanently monitor strain and temperature on sand screen products for gravel-pack and frac-pack applications. This technology, especially when paired with an optical wet connect, provides for long-term reservoir monitoring at the sandface, resulting in early detection of subsurface movements at a high resolution. With this information, operators can plan early mitigative actions, and monitor the results of these actions in real time.

This fiber support device provides a means of holding a helically wrapped optic fiber rigidly in place at the sandface, with no negative impact on the sand control functionality of the sand screens. New techniques were developed to manufacture this technology, as well as a new method to install the fiber. Dry connects have also been developed to allow connections between individual sand screens and enable longer monitored intervals.

The paper will describe this new technology, review the case history, including initial field trials, and discuss potential applications.
Engineered Particle Size Distribution While Drilling Helped Minimize Wellbore Damage in Sandstone Reservoirs
Authors: Mohamed Monir
Published: September 2011

Inducing formation damage in sandstone reservoirs through poor drilling fluids management can negatively affect well productivity. A detailed mud management plan that addresses fluid design and particle size monitoring can help minimize formation damage and improve well productivity. This was demonstrated successfully on 29 wells where the operator implemented an engineered oil-based drill-in fluid (DIF) and a particle size distribution (PSD) analyzer in the field while drilling the reservoir.

The oil-based DIF was formulated with a 70/30 oil/water ratio (OWR) and then treated with a sized calcium carbonate bridging agent to minimize spurt and total fluid loss. The PSD analyzer was used to continuously monitor and maintain optimal PSD values in the DIF. In addition, core samples were examined using a scanning electron microscope (SEM) to determine an average pore size value. The bridging agent treatment was engineered to help minimize formation damage that results from the invasion of fines, or colloidal solids. Overbalance pressures were also minimized to avoid the risk of differential sticking. The reservoir section was drilled with controlled rates of penetration.

To achieve better bridging results, D90, D50 and D10 particle size distributions were maintained in the programmed range throughout the entire reservoir section. Upon reaching total depth (TD), the bottomhole assembly (BHA) was changed to a reaming assembly and the entire open-hole section was reamed to TD.

After the open hole was deemed in good condition, the well was displaced to a solids-free invert emulsion mud with the same density as the DIF.

A total of 29 wells have been successfully drilled and completed with sand screens using this mud management plan. Testing results indicated minimum skin damage and good stable production rates.
Real-Time Operations Portal (Nibras): Another Step En Route to a Smart Field Management
Authors: Shihab Sufyan , Khadhuri Shaikhan , Busaidy Salim , Bettembourg Solenn
Published: September 2011

Managing oil fields in the best way possible has always been in the centre of interests for various oil companies; production maintenance and optimisation, deferment minimisation, efficient monitoring of well reservoir & facility performances, cross-function collaboration, and many other related issues, all represent the building blocks in a successful and efficient field management structure. The Fahud cluster of Petroleum Development of Oman has been running for more than four decades, and still contributes significantly to the company's total production. Hence, it is becoming more important than ever to ensure that the field is managed both optimally and efficiently to adequately handle the large stock of wells and facility units, and all other related issues, such as operations, services, human resources, etc. For this, a series of initiatives were adopted with the aim of achieving an efficiently monitored & controlled asset as well as highly synchronised multi-team actions.

In this paper, a web-portal based tool is presented; Nibras is a "smart" platform for Well & Reservoir Management (WRM). The standard data sources, web-accessibility, multi-levels of data presentation, exception-based surveillance, and compatibility with third-party tools, are just some of the many features and capabilities that Nibras possesses. These features has made it possible to detect problems and\or outstanding issues earlier, react to them faster, and thus decide better. Nibras has become a key enabler of the Fahud Collaboration Centre (the first operational collaborative work environment in Petroleum Development of Oman), as it provides a common ground for various asset teams from which data and information can be retrieved from standard sources. This has eliminated confusion and miscommunication that may typically result from referring to different tools, retrieving data from different sources, and presenting data in different formats.

Nibras has been approved for pan-PDO implementation, as it represents a leap towards a smarter management of oil fields. The implementation of Nibras –alongside other smart initiatives- has resulted in reduced well downtime (and hence reduced deferments), early detection of problems, more efficient decision making, and better cross-team knowledge sharing.
Utilizing NMR and Formation Pressure Testing While Drilling to Place Water Injectors Optimally in a Field in Saudi Arabia
Authors: Al-Shehri Dhafer , Kanfar Mohammed , Al-Ansari Yusuf , Abu Faizal Syed
Published: September 2011

The presence of tar or heavy oil that does not flow using conventional production technologies brings numerous challenges during field developments. Tar, acting as a permeability barrier, would often break flow or pressure communication from the aquifer to the oil zone. This results in inadequate pressure support, which is necessary for sustaining production levels and maximizing oil recovery. One of the key issues in developing a field with known tar mat accumulation is to optimally place injectors away from the tar. The problem becomes more complicated when the exact location of a tar mat is uncertain either laterally or vertically. Tar mats usually are neither flat nor uniform in thickness across a field. These uncertainties pose a challenge in planning wells especially water injectors.

Detection of tar is critical for reservoir characterization, reserves calculation and well placement. Direct and indirect techniques are employed to detect tar including core analysis, well testing, wireline logging and Pyrolitic Oil Productivity Index (POPI). These measurements are good indicators of tar; however, the challenge is to identify the tar while drilling the well. Early detection requires the deployment of logging while drilling (LWD) technologies for real-time interpretation of data.

In order to accurately identify tar in reservoir sections in real-time, integrating conventional LWD measurements with new technologies such as the slim hole Nuclear Magnetic Resonance (NMR) and the formation pressure measurements while drilling (FPWD) is necessary. This will allow for timely adjustment to the well path and prevent costly remedial actions

This paper discusses successful real-time application of slim-hole NMR and FPWD technologies to detect tar and optimally place water injectors. This is demonstrated with two case studies involving extended reach power water injectors.
Using Streamline and Reservoir Simulation to Improve Waterflood Management
Authors: Al-Zawawi Ahmed S. , Hayder M. Ehtesham , Baddourah Majdi A. , Abd Karim Mohd Ghazali , Hidayat Wahyu
Published: September 2011

Streamlines provide snapshots of flow patterns in the field, which simulation engineers can use to shorten the history match cycle when validating reservoir models. They can also help engineers develop injection strategies and improve the sweep efficiency by analyzing flow patterns and by estimating injector to producer relationships in the field during computations of various prediction scenarios. Our strategy in this study is to use details of reservoir conditions obtained by traditional reservoir simulations and calculate streamlines from the computed flow field. Saudi Aramco's in-house developed simulator POWERS and its post processing environment have been enhanced to generate streamlines from computed reservoir flow fields. A streamline tracing software developed at Texas A&M University and POWERS has been customized to generate streamline outputs. The algorithm used for computations is parallelized to run on Linux clusters. Several features, such as computations of injector/producer allocation factor and injector efficiencies, have been implemented in our streamline generation tool kit. In this paper, we present two case studies to illustrate advantages of streamlines when used in a workflow along with reservoir simulations to improve water flow managements of the field. Our analysis resulted in an optimal design with a fewer number of injectors to maintain the production target. In addition, streamline analysis helped us to find optimal well locations for injectors.
Maximising Oil Recovery of a Thin Oil Rim through an Optimised Field Development Plan
Authors: Garimella Sai , Harris Jeremy , Kalbani Ali , Lamki Ali , Khabouri Khalid
Published: September 2011

PDO operates many oil fields in Oman and maintains a periodical update of Field Development Plans (FDP). This paper presents a case study of one such green field where a FDP was performed that proposed numerous development wells targeting a thin oil rim overlain by a gas cap in two clastic transition-zone reservoirs. When drilling commenced, surprises were encountered such as steeper flanks, lower gross rates, higher water cut, faster pressure depletion & uncertain facies distribution. A comparison of earlier models against actual results lead to revisions mainly in vertical compartmentalization, reduced horizontal & vertical permeability. This severely impacted achieving business targets, and sub optimal use of drilling resources & surface facilities.

A new FDP Study was initiated to understand the performance and provide a revised development strategy under pressure depletion conditions. The study also evaluated the merit of installing gas lift and the impact of gas cap pressure maintenance. Revised static & dynamic models were built with the current understanding from wells drilled since the previous FDP. The simulation model was history matched with field production & pressure data and then used to identify future well locations and optimum placement within the oil rim. Additionally, the numerical model was used to assess multiple development options such as oil gains arising from gas lift installation, assessment of an additional high-pressure gas compressor for deeper gas-lifting and an additional gas export pipeline.

A fit-for-purpose uncertainty analysis of static and dynamic parameters was then undertaken to understand the range of uncertainty on field ultimate recovery. Screening of gas cap pressure maintenance resulted in a sizeable incremental oil volume over the depletion development, thus paving the way for future detailed concept selection of pressure maintenance field development. The study also resulted in identification of future infill well locations, immediate need for installation of gaslift and negated the need for an additional high pressure compressor & invalidated an additional gas export pipeline.

Robust static & dynamic models were built through multiple iterations to provide a guiding tool for future development planning. The adopted methodology described in this paper to evaluate the various development aspects is generic and could be useful in typical field developments.
Completion and Stimulation Challenges and Solutions for Extended-Reach Multizone Horizontal Wells in Carbonate Formations
Authors: Jackson Alfred , Jorden John , Al Marzouqi Mohamed Abdulla , Al Mahri Ali Eissa , Keller Stu , Shuchart Chris
Published: September 2011

To develop a giant carbonate oil field offshore Abu Dhabi, more than 300 wells are planned to be drilled from 4–6 artificial islands. Current plans are for these wells to be linear maximum reservoir contact (MRC) wells having horizontal completion intervals of 10,000 ft. A significant number of the wells will be extended-reach (ER) wells having measured depths exceeding 20,000 ft, and a number of the wells will have measured depths greater than 30,000 ft. One of the main challenges for these linear MRC wells is achieving adequate acid stimulation over the 10,000-ft completion interval. This paper discusses completion and stimulation options for these wells. Several of these options are illustrated by two 10,000-ft-completion-interval linear MRC pilot wells that have been drilled, completed, and stimulated from existing wellhead platform towers. These pilot wells were completed with preperforated liners equipped with ten swell packers. The stimulation treatment was performed using coiled tubing and a radial jetting tool. The completion design for a third linear MRC pilot well is also discussed. This well has been designed with a solid liner containing more than 15 swell packers and more than 35 inflow control devices (ICDs). The stimulation treatment will be performed through the ICDs. The paper also discusses a new concept for completing these types of wells using ICDs and acidizing check valves.
Evolution of Tight-Gas Fracturing Methodology in the Lower Paleozoic Sandstone Formations of Saudi Arabia
Authors: Al-jalal Ziad , Ramsey Lee , Gurmen Nihat , Kalinin Daniel
Published: September 2011

The lower Paleozoic Sandstone Formations in Saudi Arabia range from as deep as 20,000 ft in the South Ghawar and Rub'Al-Khali to less than 12,000 ft in the northwest. The deeper, tight-gas projects in the South Ghawar and Rub'Al-Khali have seen the highest activity since 2006. They are the subject of this review in light of four key wells. The targeted lower Paleozoic formations in these wells are Sarah, Qasim, and the Rhuddannian sandstones in the Qusaiba formation. The Sarah and Qasim formations are sandstones while the Qusaiba is interbedded sandstone and shale. The high pressure, high temperature (HPHT) environment in these reservoirs poses serious technical challenges that must be overcome when hydraulic fracture stimulation is attempted.

Specific challenges to fracture treatment design in these deep, lower Paleozoic intervals include proppant selection, interaction of fracturing fluid with the formation, interaction of fracturing fluid with drilling mud, fracturing fluid clean-up and load recovery. The four key wells show an evolution in the design methodology to meet these technical challenges. The evolutionary steps take into account geological, geomechanical, and petrophysical analyses that are calibrated with field data as the project matured. The accompanying lab work has also led to permeability profiles, well-calibrated stress regimes, and, overall, an enhanced understanding of these complex reservoirs. In turn, better reservoir understanding has improved the completion strategy.

The four key wells provide a detailed account and up-to-date documentation of the experiences gained in the last four years. Early on, a fluid selection strategy was developed based on the fracture gradient. As field data became available, geomechanics studies determined that fracture confinement was the result of a change in the stress regime. Finally, the need for multistage fracturing was established to optimize production. The lessons learned from these experiences have guided future exploration activities in the area.
Alternate Deployed Systems Application Guide
Authors: Bebak K. T. , Wisnewski Matt
Published: September 2011

Interest in alternative deployment methods for electrical submersible pumps has been growing in recent years. The drivers are to decrease intervention time and rig cost, to replace offshore workover rigs in environmentally sensitive areas and in remote areas with no access roads and to open the opportunity for subsea intervention. Many new technologies are being brought to market in an effort to meet the varying needs of operators around the world. Deciding upon the most technically and economically effective solution will be critical to an operator's ultimate success.

This paper will investigate a number of different deployment methods, such as conventional tubing, coil tubing with external power cable, coil tubing with internal power cable, power cable deployed, thru tubing conveyed, and wireline deployed. Some of these technologies have installation histories; some are still in their infancy Advantages and disadvantages as well as application parameters for each deployment method will be discussed. In addition, this paper details operational use of a number of the more prevalent methods in use today. The information is summarized in a key criteria guide and the bibliography will provide a useful listing of key sources for more detailed information.

The data contained in this paper will assist operators in choosing the most effective and reliable alternate deployment methods for their particular application. Information from various operators has been compiled to provide actual field usage data to support the implementation of alternate deployed systems
Evolution of Petrophysical Data Management in Saudi Aramco
Authors: Al-Ghamdi Turki , Al-Ali Hussein , Zahdan Ghassan , Al-Nahwi Ibrahim , Tjwan Tjan , Readean Muhammad
Published: September 2011

Well log data is used by exploration and producing (E&P) professionals to locate new well locations, conduct reservoir characterization studies, optimize well placement programs, enhance fluid monitoring plans and improve well completion strategies.

In response to the increased worldwide demand for oil and gas, Saudi Aramco has tripled its rig count. The resulting increase in well data has introduced new log acquisition and processing challenges. Saudi Aramco recognizes the importance of well log data management as a significant mission required to address the needs of E&P professionals to obtain high-quality well log data at any time and in many different formats.

Saudi Aramco started collecting log data with the first wells drilled in the 1930s. Over time, both the data types and data formats have changed with the introduction of new logging tools and technologies. Tracing the development of petrophysical data management through these years will help us to define our future vision and honor the lessons and best practices learned in the past.

In contrast to early paper-based and more recent digital log management systems, various groups at Saudi Aramco have jointly developed new systems that provide real-time data delivery from the well head to the desktop. These new systems allow well log service providers and E&P professionals to work collaboratively within an efficient, unified data management environment that improves both data quality and efficiency. New automated and semi-automated workflows reduce data delivery times, improve data quality, and log data is now easily distributed in a variety of formats to different end-user systems. The new system also provides time-based workflow monitoring, allowing managers to review internal performance and to gauge the performance of logging vendors against service level agreements.
Challenges in Attracting and Retaining Females in the Oil Industry to Meet a Diverse, Equal, and Inclusive Workforce
Authors: Wafa Yasmine
Published: September 2011

Gender is a business issue, not a "women's issue". The under-use of women's talent has an impact on the bottom-line. Organizations that see women not as a problem but as a solution and treats them not as minority but as full partners in leadership are the organizations that are able to make use of their full potential.

An organization's success and competitiveness is realized when it can successfully manage a diverse and inclusive workforce. The oil industry has been historically a male-dominated sector. For example, per the European Labor Force Survey, females comprise only 9% of UK engineering professionals, 18% in Spain, 26% in Sweden, and 20% in Italy.

Companies are often not ready to seamlessly absorb women into the oil sector, especially in the Middle East, due to many factors. General issues include females' dual life style (work and home) roles, accommodation for females, challenging work hours, and feeling insecure and unsafe in remote locations. Middle Eastern-specific issues include culture and religion; for example, a family's acceptance of their daughter/spouse working on a rig among male colleagues and spending nights and weeks away from the family house.

Oil companies are now focusing more on targeting female engineers to bring diversity to the oil industry. Those selected engineers are required to undergo certain orientation and training programs that should help them get harmonized in the industry.

The goal is an approach to gender that includes both halves of the human race. The aim is a new kind of "bilingual" leadership, one that maximizes the abilities and potential of both men and women by recognizing the competitive advantages of our complementary skills and natures. Successful integration of women would ensure greater benefits for the oil industry and create a more equitable society. Such integration is not easy but, when done well, it can have a transformative effect. This paper does not take the view that women are better than men. It takes view on how to capitalize on both genders in an organization. It will discuss issues and solutions for this new direction of the industry.
Kidan Sour Gas - Close Upstream Collaboration between Shell and Saudi Aramco Leads to Improved Understanding of a Complex Sour Gas Field
Authors: Briner Andreas , Holstege Gijs C. , Al-Nasser Kadhem , Daou Elie , Wood Peter
Published: September 2011

The South Rub Al-Khali Company Limited (SRAK) is an incorporated Joint Venture between Shell and Saudi Aramco to explore for non-associated gas and associated liquids in the South Rub'Al-Khali Basin in the Kingdom of Saudi Arabia. SRAK's contract area includes substantial volumes of ultra-sour gas in structures known collectively as Kidan. These were discovered in the 1960's by Saudi Aramco and have been appraised with several wells since then but not developed thusfar.

Alongside the exploration campaign targeting the deeper Paleozoic play, the venture has carried out substantial data gathering and evaluation of the overlying Jurassic sour gas contained in the Kidan structures (Figure 1). To enable the appropriate and most cost-effective development to be selected requires a rigorous approach to project planning with focus on up-front understanding of the complexities of the reservoir.

Extensive data gathering at the front end stage of the project has therefore been a key part of SRAK's strategy resulting in high quality datasets from two wells located on the Kidan North structure and a well on the Kidan South structure have been acquired. These data include core, openhole logs, fluid samples and production test data.
Underbalanced Drilling (UBD) as a Tool to Test Tight Gas Plays – An Example from the Empty Quarter, Saudi Arabia: Drilling and Reservoir Characterisation Lessons
Authors: Al-Maashari Yousuf , Briner Andreas , Axon Andrew , Wevers Adrian
Published: September 2011

Executive Summary

The South Rub Al-Khali Company Limited (SRAK) is an incorporated Joint Venture formed by Shell Saudi Ventures Limited (50% share) and Saudi Arabian Oil Company (50% share) to explore for non-associated gas and associated liquids in the South Rub'Al-Khali Basin (Empty Quarter) in the Kingdom of Saudi Arabia.

This paper discusses specific data acquisition strategies that have been developed to address the challenges of deep wells in tight reservoirs in remote and harsh environments. While drilling the first three wells SRAK has gone through a very steep learning curve with respect to well data acquisition and integration. It also allowed optimising the data acquisition strategy for future wells that SRAK was planning to drill.

As a direct result of this initial work, and the experience gained by other wells drilled in the Rub' Al-Khali, SRAK realised that the traditional approach and formation evaluation using static well data gathering was not entirely satisfactory. Industry experience also showed that tight gas exploration and appraisal wells historically involved lengthy multi-year multi-well programs due to inconclusive results from static logging, coring and well testing operations.

In line with Shell's global initiative to use underbalanced drilling (UBD) for tight gas exploration and appraisal, UBD was implemented in SRAK's fifth exploration well in the Rub'Al-Khali. The deeper Palaeozoic reservoirs in the Rub'Al-Khali are known to be commonly tight and susceptible to near-wellbore formation impairment during conventional overbalanced drilling. UBD offered a possible solution for better quality reservoir evaluation and demonstrating any un-impaired potential flow. In other prospects, previous conventional drilling, stimulation and well clean-up had typically failed to unambiguously characterise pay and produce hydrocarbons to surface.

UBD drilling operations were designed and implemented with the support and expertise of the shareholders. Both internal and external subject matter experts supported operations. Whilst numerous UBD specific drilling related aspects were understood pre-drill, significant uncertainty remained around data acquisition and interpretation during UBD drilling operations.

The SRAK UBD project was safe and successfully executed as per the drilling program. Due to the UBD operations there was no ambiguity on presence and mobility of hydrocarbons, thereby avoiding SRAK the completion, fraccing and testing cost which are far higher than the UBD expenditure.

The well SRAK-5 offered firsthand experience to the SRAK team to assess the advantage and disadvantage of UBD operations on reservoir characterisation. This paper aims to capture SRAK's learning in UBD drilling and reservoir characterisation.
Identifying Stress Transfer in CSS Reservoir Operations Through Integrated Microseismic Solutions
Authors: Prince Marc , Baig Adam , Urbancic Ted
Published: September 2011

Advanced seismic analysis approaches are used to examine possible correlations between various seismic characteristics and observed in-situ pressure readings as related to CSS heavy oil operations in Canada. In particular, we examined how seismic parameters such as cumulative strain, apparent volume, energy surplus, and cumulative occurrence rates can be used to identify the dynamic transfer of stress from the reservoir to generating depths, generating conditions for possible failure of the cap rock.

These techniques are not only applicable to Canadian oil sands, but potentially to any environment where significant deformation results in seismic events giving the opportunity for a real-time analysis of failure conditions.

Based on our analyses, changes in cumulative strain mimic observed pressure changes. Similarly, a resulting increase in energy surplus occurred at reservoir depth coincident with the occurrence of observed pressure spikes, followed by a subsequent increase in apparent volume and cumulative occurrence rates at shallower depth subsequent to the observed pressure spikes.

Our observations suggest that advanced seismic analysis techniques can be used to potentially identify the transfer of strain and stress from the reservoir to shallower depths and provide the potential to provide real-time feedback mechanism on reservoir behaviour based on observed microseismicity.
Intelligent Fields: Industry's Frontier & Opportunities
Authors: AL-Dhubaib Tofig A.
Published: September 2011

Digital Field capability is at the leading edge of the Oil & Gas industry. This capability is a result of continual advancements and integration of well technologies, communications, process control, and E&P computing technologies. Digital Field capabilities enable the integration and use of surface and subsurface real time data, to optimize upstream assets and profitability. This capability has been given different names, such as Intelligent Fields, Smart fields, Digital Oil Field of the Future, integrated field and Integrated Operations. In Saudi Aramco, this capability is being leveraged through four major projects: "Real-time Drilling Operations" for optimal drilling; "Geosteering" for optimal well placement within the reservoir; "Intelligent Fields" for optimizing reservoir management, production and production operations; and "Event Solutions" for optimal field development. Throughout this paper, the term "Digital Field" will be used as the nomenclature for this capability.

This paper provides an introduction and background on Digital Field capabilities and presents Saudi Aramco's experience in leveraging them in key upstream business processes. The paper also highlights areas of applications, challenges, lessons learned, values attained and the opportunities that this brings to the industry as experienced through Saudi Aramco implementations.
Environmentally Friendly Dispersants for HP/HT Aqueous Drilling Fluids Containing Mn3O4, Contaminated With Cement, Rock Salt, and Clay
Authors: Kar Yusuf , Al Moajil Abdullah M. , Nasr-El-Din Hisham A. , Al-Bagoury Mohamed , Steele Christopher D.
Published: September 2011

Dispersants are widely used in drilling fluids to prevent solids flocculation and to control the rheological properties of the fluids. There is high demand for effective, thermally stable and environmentally friendly dispersants for HPHT drilling fluids. This work was undertaken to investigate the use of environmentally friendly dispersants in HPHT aqueous drilling fluids containing manganese tetroxide (Mn3O4) as the weighting agent. The dispersants were chosen because they are non-toxic to aquatic organisms and biodegradable. The effects of cement, rock salt and clay particles as contaminants on the dispersant performance and the fluid properties were investigated. The dispersants were lab tested in high density fluids of 2.1 g/cm3 at a temperature of 200°C and pressure of 500 psi. The fluids were analyzed before and after heat-aging using rheometer, sag test, light scattering, and HPHT fluid loss.

Out of over 100 dispersants tested, two dispersants showed best performance in controlling the flow behavior of the fluids in the presence of contaminants. Dispersant A is a synthetic copolymer of maleic anhydride and acrylic acid and dispersant B is an anionic lignosulfonate. They are compatible with water based drilling fluid system having manganese tetroxide as the weighting agent (SG = 2.1) and thermally stable (150-250 °C). Both dispersants lowered the rheology including plastic viscosity and yield point before and after heat aging (200°C) when compared to blank. They show also lower sag and fluid loss values in the presence of contaminants and lowered the filter cake thickness.
A New Productivity Index Formula for ESP-Lifted Wells
Authors: Al Gahtani Abdallah
Published: September 2011

The productivity index, PI has been used as a measure of the potential of wells to flow at certain formation pressure drawdown. Additionally, it is used to measure formation damage and formation potential to flow capacity.

In ESP-lifted wells, the pressure is boosted by the added number of pump stages. Hence, pump curves are used to describe the outflow performance of such wells. These curves, however, were generated at test bench using water which is a single phase. Because of this, a large error in estimating the performance of oil wells as multiphase flow is pumped through. Additionally, the rate of degradation of pump performance as multiphase flow is pumped is not fully understood in different pump stage design. Moreover, these pump curves are used by ESP design software's which are commercial with limited licensing.

This paper presents a new analytical solution for precisely calculating the productivity index of ESP-lifted wells by which classical pressure traverse calculation can be made using conventional Nodal analysis software. In addition, the approach yields more accurate calculations as it can be calibrated and it eliminates the compounded error in calculation by using pump curves. This method relies on augmenting the effect of pump stages into the induced pressure changes part of the formula.
Experimental Evaluation of Viscoelastic Surfactant Acid Diversion for Carbonate Reservoirs: Parameters and Performance Analysis
Authors: Al-Otaibi Msalli A. , Al-Muntasheri Ghaithan A. , Hussein Ibnelwaleed A. , Chang Frank F.
Published: September 2011

Formation damage minimization and removal are essential to field productivity enhancement and production target achievement. While formation damage is anticipated during drilling, an effective treatment fluid becomes important to bypass mud damage and enhance well productivity. Most of the fluids used in acid stimulation of carbonate wells are consumed in the high permeable zones – leaving the low permeability and damaged zones not effectively stimulated.

Viscoelastic surfactants (VES) have been introduced in the industry to overcome this challenge and offer effective uniform treatment over long horizontal well intervals to treat damaged and low permeability zones. The viscoelastic surfactant molecules form rod-like micelles in the presence of salt at specific pH condition, which results in significant viscosity increase. Therefore, when added to acid systems, the VES helps in increasing the viscosity of the solution based on the state of the acid-carbonate rock reaction. Customizing the treatment to the field's needs is a key factor to the success of the stimulation treatment. The treatment design includes the carrying fluid type and VES concentration. These parameters need to be optimized to achieve a uniform distribution of the treatment and effective acid diversion.

This paper studies the diversion ability of VES acid system in comparison to straight acid systems. Also, it evaluates the impact of permeability, salinity, and VES concentration on the diversion efficiency of the VES acid system. For the first time in the industry, the diversion efficiency was shown through return permeability results to be heavily dependent on salinity of the mixing water, VES concentration, and permeability contrast. Increasing the salinity and VES concentration enhanced the diversion efficiency significantly, while increasing the permeability contrast reduced the diversion efficiency.

Core flooding equipment capable of flowing two parallel core samples was used to study the VES acid system diversion efficiency at various permeability contrasts. Carbonate core samples with permeabilities in the range of 0.7-56.25 mD were used in the study. The VES acid system carrying fluid salinity effect was investigated by comparing the diversion obtained by distilled water, field water and seawater at different VES concentrations. Two VES concentrations were used to evaluate its impact on diversion, 3.75% and 7.5%. These parameters were studied at 1,000 psi for pore pressure, 2,000 psi for confining pressure, and 150 °F for temperature.
The Role of Geomechanics in Diagnosing Drilling Hazards and Providing Solutions to the Northern Iraq Fields
Authors: Abalioglu I. , Legarre H. , Garland C. , Sallier B. , Gao J. , van Galen M. , Chou Q. , Neil B. , Soroush H. , Qutob H. , Mahli Z.
Published: September 2011

The integrity of the wellbore plays an important role in petroleum operations (e.g., drilling, completion, production). Hole failure problems cost the petroleum industry several billions of dollars each year. Prevention of wellbore failure requires a strong understanding of the interaction between formation strength, in-situ stresses, and drilling practices. As in-situ stress and rock strength cannot be easily controlled, adjusting the drilling practices (i.e., selecting optimal trajectory and bottom-hole pressure) is the usual way to inhibit wellbore failure.

Drilling in the problematic Kolosh formation in Kurdistan has always been associated with several wellbore stability problems (e.g., hole washout, stuck pipe, extra cuttings/cavings, tight holes). This has caused large amounts of non-productive time to drilling programs and the drilling of sidetracks in some of the wells in this field. A review of the drilling reports and dual-caliper logs from offset wells in the area revealed large amounts of washouts in the middle Kolosh section. These indicators demonstrated the requirement for performing a geomechanical modeling and wellbore stability study to mitigate such problems in future drilling operations.

In this paper, local in-situ stress magnitudes, orientations, and formation pressures were characterized. For this purpose, data was analyzed from offset wells (e.g., borehole breakout data, bulk density logs, wireline formation tests, drillstem tests, pressure build-up tests, formation pressure data in this area). The mechanical properties of the formation (including dynamic and static Young's modulus, Poisson's ratio, and rock strength) were evaluated using sonic, density, and gamma ray logs. A rock mechanical properties database and data management software was applied to correlate the calculated dynamic elastic properties to the most appropriate static rock strength and stiffness parameters for a base case wellbore stability model and subsequent sensitivity analyses. 2D elastoplastic and 3D linear elastic models were used to back-analyze the hole collapse and enlargement in the selected offset wells to evaluate and calibrate the geomechanical model. Wellbore stability software was used for this purpose. Finally, a mud weight window was defined, and the optimum profile of the mud weight was recommended for drilling through the Kolosh formations. Due to a narrow mud weight window, additional potential problems were investigated including the possibility of fracturing at the top of Kolosh formation. Finally, relevant solutions were presented.
Innovative Chemistry for Drilling Fluid Additives
Authors: Zheng Jun , Wang Jianzhao , Musa Osama M. , Farrar David , Cockcroft Bob , Robinson Alison , Gibbison Robert
Published: September 2011

The enhanced performance of drilling fluids, especially High-Temperature, High-Pressure (HTHP) compatibility, will allow faster and safer drilling in challenging environments. This paper presents a novel class of synthetic polymers that were developed as high performance rheology modifiers (viscosifiers). The leading polymer candidate was shown to be an effective thickener, with excellent salt-tolerance and thermal stability compared to conventional viscosifiers used in water-based drilling fluids.

This new class of synthetic polymers was suitable for demanding drilling conditions where conventional viscosifiers cannot perform satisfactorily. For example, xanthan gum is known to start losing rheological properties above 250-300°F so it is not always suitable for HTHP drilling operations. A desired rheology modifier should possess similar rheological properties to xanthan gum (e.g. highly shear thinning) with enhanced salt tolerance and thermal stability. These enhanced properties will allow drilling fluids to maintain critical functions under harsher field conditions.

This paper presents the basic characteristics of the newly developed polymeric rheology modifier as well as its rheological and thermal stability properties. The rheological properties of the polymers were studied in fresh water, in brines and in formulated drilling fluids. Thermal stability studies were conducted using stainless steel pressure aging cells, a roller oven, and a conventional oven. The novel polymer developed was shown to exhibit a similar thickening efficiency and rheological profile (i.e. shear thinning) to xanthan gum. After thermal aging up to 350–375°F (177–190°C) for 16 hours, drilling fluids based on this polymer were shown to maintain excellent rheology and suspension power. The new synthetic rheology modifier also demonstrated synergistic effects with other ingredients commonly used in water-based drilling fluids, further enhancing thermal stability.

Development of these high-performance drilling fluid additives is critically important to the drilling industry. HTHP compatible drilling fluids may allow more environmentally-friendly drilling operations to be undertaken in a safe and efficient manner.
Universal Technique Normalizes and Plans Various Well-Paths for Directional Drilling
Authors: Liu Xiushan
Published: September 2011

Appropriate well-path planning is the prerequisite for operators to drill directional and horizontal wells successfully. Since the goal of drilling is to tap the oil from the complex reservoirs, and the well-path design requirements, subsequently, are different. Operators generally plan a directional or horizontal well in a 2D plane if no special requirements are imposed, and mostly consider the build and drop well sections as circular arcs. It seems very easy to plan such a simple profile, but conventional techniques are so inconvenient for use, as highlighted in the following situations:

Conventional methods require different formulas for planning different well profiles. Thus, the variety of well profiles leads to the variety of design formulas and methods. Conventional methods only consider the section length and inclination angle of a hold section as unknown parameters while planning a well profile. It means that other parameters of the well profile are given as known parameters and can not be directly designed to meet the specific requirements. Conventional methods only provide one set of formulas for a well profile and often require trial-and-error procedures to get the reasonable results. Well planners have to make tentative calculations again and again, and hardly exclude the interference of subjective factor.

This article provides a universal method of normalizing and planning various well profiles, which includes two core technologies. First, the author constructs a general-purpose well profile that covers all of arc-type profiles those consist of circular-arc and straight-line sections with any combination. Secondly, the author presents the constraint equations and all of possible analytical solutions, which yields a new technique of planning a well profile that any two characteristic parameters can be arbitrarily selected as unknowns.

The universal solution presented for planning various well profiles achieves the mutual validation and optimization of characteristic parameters among one another, and solves the problems on the variety and optimization of well profile design. The methods proposed represent significant improvements over the conventional well-path planning techniques, were programmed into computer software, and have proven satisfactory for several hundreds of directional and horizontal wells.
Effect of Drill Solids on the Prediction Accuracy of a Viscosity Model
Authors: Misra Garima , Jamison Dale E. , Whitfill Donald L.
Published: September 2011

Lost circulation is one of the most troublesome and expensive problems encountered in drilling. Software with specialized modules may reduce the number of lost circulation incidents by improving understanding and planning. Hydraulic modeling and design software can predict the equivalent circulating density (ECD) throughout an interval. By selecting another module, the user can calculate the fracture width that may be initiated and optimize the material and particle size distribution to help achieve effective propping and plugging of the fracture. Rheology changes resulting from the addition of specialized lost circulation material (LCM) can be determined with another module, and this information is then cycled back to update ECD calculations.

The viscosity module predicts the LCM-laden fluid viscosity for both non-aqueous and non-dispersed aqueous fluids quite well. Additional laboratory experiments have validated the current module for other parameters, such as prediction accuracy with drill solids present in both water- and oil-based systems. A wider range of mud weights was also evaluated. The data shows that the presence of three different types of drill solids, even in substantial amounts, does not affect the prediction accuracy of the current viscosity module. The ECD calculations performed on both measured and predicted rheologies resulted in percent errors in the range of 0.06 to 4%, which is acceptable for hydraulics analysis and indicates the accuracy limit.