bluuebunny/crossref_metadata_2025 huggingface dataset:
An Innovative Inflow Control Device Technology with Sliding Sleeve Functionality Maximizes Recovery in Horizontal Wells
Authors: Lee Byung , Julaih Ali Al , Gavioli Paolo , Vicario Roberto , Suherdiana Hedy
Published: March 2015

Horizontal wells drilled in heterogeneous reservoirs present several challenges for reservoir management. Issues like early water breakthrough and inefficient drainage around the well in a reservoir with high contrast in permeability are very common in horizontal wells. An effective approach to address the challenges of horizontal wells and to increase the oil recovery is to complete the wells with inflow control device (ICD) technology.

Most ICD technologies available in the market are passive inflow control devices that do not have the ability to change properties when unwanted fluids break through. The new ICD not only incorporates the benefits of passive ICD technology, it also incorporates sliding sleeves in the module that can be closed whenever the ICD starts producing water. This helps maximize the oil production from the well and reduces the problems related to handling of water at the surface facilities.

This paper will demonstrate the effectiveness of the new hybrid ICD design. It is novel viscosity insensitive and may provide higher restriction to water over oil, and the successful operation of the sliding sleeve feature through a field case of a well drilled in a carbonate field in Middle East. Bottomhole pressure and weight indication observed through specialized fiber optic-installed coiled tubing confirmed the operability of technology by proper opening and closing of sliding sleeve. A fluid flow profile recorded by a production logging tool (PLT) on the same CT proved that the completion effectively equalized flow along the wellbore and will delay eventual water breakthrough while still producing at the desired production rates. PLT proved that the custom-designed completion with its appropriate number of compartments, number of ICD joints and flow resistance rating, achieved an optimized ICD completion.
Flow-Based Effective Properties of Sub-Seismic Karst
Authors: Jones Gareth D
Published: March 2015

Evaluating uncertainty in reservoir performance related to karst is a fundamental challenge for field development planning and optimizing recovery. Deciding which karst features matter-to flow and how to capture their effect for flow simulation is a critical, but uncertain step in developing an appropriate reservoir characterization and modeling strategy.

Our ability to characterize karst is compromised by the type, resolution and relative abundance of different measurement methods. Many sub-seismic karst features fall in a “data gap” because they have dimensions and networks of pores that are not, or only partially, resolved in typical subsurface datasets. Outcrop analogs and cave maps provide a bridge to address this “data gap”. A specific challenge is how to capture the flow significance of karst features that are smaller than a full field scale geological model cell.

This paper presents a workflow using high resolution geologic models termed element modes to address this karst characterization and modeling challenge. Element models were populated with distinct geological configurations of sub-seismic karst and matrix. Flow-based averaging was used to calculate the effective reservoir properties at the scale of a full field geologic model cell. Karst was populated using two different facies modeling methods: 1) Object Based Modeling (OBM) and 2) Multiple Point Statistics (MPS).

Results for two karst examples presented demonstrate that the presence of certain types of karst, even < 5% by volume in a geological model cell, can increase the vertical permeability by an order of magnitude or more relative to a matrix only case. In contrast the effect of karst on horizontal permeability is less significant. Permeability anisotropy (kz:kx) is therefore increased. The karst: matrix property is common to both the element and full field model and can be used as the link to populate effective properties at the field scale.

“Model Assisted Characterization” experiments with efficient fast-to-run high resolution element models, that capture distinct styles of karst, in combination with flow-based averaging optimizes the characterization workflow and provides a richer understanding of irreducible uncertainty that expedites geologic model design.
Developing People through Mentoring to Transfer Knowledge and Technology
Authors: Al-Mutairi Saleh H , Al-Jummah Reem J. , Bou-Mikael Sami , Al-Aruri Ahmad D. , Raju Vegesna Venkata , Izzett Paul
Published: March 2015

Saudi Arabian Chevron (SAC) is continuously investing in human resource development and technology as an integral part of its business operations. Newly hired graduates go through a variety of training and performance management programs to enable them to be globally competitive members of the Chevron workforce. A comprehensive and structured manpower development program called “Horizons” is implemented within Chevron to accelerate the development of new graduate hires.

A key enabler for delivering on SACs graduate development commitments is through its newly inaugurated Technology Center. The Technology Center is acting as the center of excellence for manpower development and technology transfer to SAC. The Horizons program consists of three key elements; a) technical training; b) rotating job assignments; and c) mentoring. Technical training, with a mix of both cross-functional and discipline specific topics, is designed to improve competencies of new graduates. Rotating job assignments allow participants to gain practical experience and petrotechnical skills by becoming involved in a variety of hands-on projects. The mentoring program assigns each young employee with a senior technical professional to enhance competency through knowledge sharing and to guide the career planning and development process. The SAC Technology Center provides technical support to the assets through various projects, including technology deployment, static and dynamic modeling, reservoir management and drilling and completions technology. A key objective in all of the Technology Center projects is to provide opportunities for the young national talent to learn through enganement in ongoing projects.

This paper highlights key components of the accelerated development program and technology transfer process implemented in Saudi Arabian Chevron by the Technology Center. With a structured and focused approach to the development of national talent, SAC feels it will be able to achieve effective and reliable transfer of the Chevron corporate culture and knowledge to meet the future human resource needs of the Company.
Geosteering Horizontal Wells in Ultra-Low Resistivity Reservoir at Flank of a Field in Northern Oman
Authors: Lim T. , Goossens P. , Soden L. , Angelatos M.
Published: March 2015

Geosteering horizontal wells in the flank of a flatly dipping structure is the focus of a PDO waterflood development project since 2006. The reservoir is a carbonate Shuaiba formation in central north Oman. As the crestal areas have been fully developed, the future development focus is in the flank, which is located within the transitional oil column. This column has a low oil saturation that can vary from 35% to 50% in the first top 2m of the reservoir. Consequently, to avoid leaving attic volumes, wells need to be placed as close as possible to top of reservoir while avoiding penetration of the highly unstable overlying shale.

This field has unique geosteering challenges. The reservoir-caprock interface is an erosional surface which is complicated further by resistive and cemented layers, faults and fractures. These features can deflect the drilling bit for a few degrees in inclination, which seriously affects the geosteering capability. Regarding log analysis implications, the ultra-low resistivity (~0.5 ohmm) in this reservoir provides little resistivity contrast with the shale roof making it very difficult to interpret the upper bed boundary. The ability to interpret the bed boundary is only compensated by the shale anisotropic effect on the propagation resistivity, which is limited to some 1m maximum depth of detection. In addition to the above, insufficient hole cleaning and tortuous trajectory will contribute to high drilling torque that poses a challenge to reach the desired well length. With these multiple challenges, experienced geosteering personnel in this field are an important factor in successful well placement.

The standard practice for geosteering in this field is to use the real time resistivity response and compare it with forward resistivity models to interpret the well position. This had been successfully done by three service companies with experienced geosteering personnel in the ongoing drilling campaign. The standard LWD suite is density, neutron, gamma ray and propagation resistivity. From the propagation resistivity tool, various compensated resistivities are being transmitted in real time and used for the well placement. Gamma ray provides a secondary indicator to indicate if the well is near to the shale caprock.

In conclusion, we are now routinely successful in geosteering horizontal wells in ultra-low resistivity and flank of a flatly dipping structure. This has proved the economic viability of transitional oil column in the flank and thus adding reserves to the field.
Comprehensive Micromodel Study to Evaluate Polymer EOR in Unconsolidated Sand Reservoirs
Authors: Herbas J.G. , Wegner J. , Hincapie R.E. , Födisch H. , Ganzer L. , Castillo J.A. Del , Mugizi Herbert Magyezi
Published: March 2015

In this work micromodels are generated from high resolution images of unconsolidated sands and subsequently used to study polymer EOR processes. Using this approach an almost unlimited number of equal copies can be produced. Moreover, compared to cores, the micromodels enable visual access to the flooding process, facilitating a more detailed process description. Understanding the mechanisms and effects of polymer flooding is essential to avoid failures in field applications. Core studies conducted by commercial laboratories indicated very optimistic oil recovery from polymer injection; therefore, a micromodel study was proposed to investigate the recovery process in detail. The experiments were conducted at reservoir temperature.

This study aims to support the design and optimization of polymer EOR projects by experimentally determining polymer performance in terms of production acceleration, incremental production and reduction of the residual oil saturation. Performance is evaluated for a variety of critical input parameters such as polymer rheology, product, and concentration for different average rock properties. The study includes complete rheological characterization of three polymers in terms of flow curves and, in specific cases, viscoelastic effects. The characterization enables the determination of suitable polymer concentrations based on three predetermined viscosity ratios. During the flooding experiment, the oil saturation changes are continuously monitored through image analysis based on which the recovery factor can be calculated.

Experimental results obtained from corefloods are compared to those obtained in micromodels, focusing on the following key parameters: (1) Recovery factor, (2) injected pore volume at breakthrough time, (3) residual oil saturation. The paper illustrates how the micromodel experiments help to improve the understanding of oil recovery processes during polymer EOR.
The Evolution of Well Testing Practices From Conventional to Zero Flaring in a Saudi Aramco Oilfield Development
Authors: Duthie L. , Arukhe J.O. , Namlah S.
Published: March 2015

Increased concerns from well testing activities about the environmental impact have left several oil industry challenges. Some of these challenges include handling well effluents from flow back operations with sour crude; the challenges can be more severe to contend with H2S safety, pollution and spill risk. Limited deck space in offshore environments often restricts the footprint of flow back equipment. An optimized solution to cater specifically for offshore operations requires careful design to ensure a safe yet functional flow back system. The pollution risk from fall out could have serious consequences to the marine life and habitat. Given that offshore operations typically cost an order of magnitude in excess of land based operations, weather uncertainties could typically result in cost overruns, increasing total job costs.

The scope of the paper is to examine the evolution of well deliverability testing — from conventional flaring practices to contemporary smokeless and zero flaring operations in a giant carbonate oil field in Saudi Arabia, surrounded by a world class environmentally protected marine and coastal ecosystem. The examination of 100 well testing candidates, with 39 of those using the zero flaring approach, allows a demonstration of the clear cost, technical and economic benefits over traditional flaring techniques.

Before the production facilities and flow lines were operational, the previous clean up method required flaring of oil and gas. Although best practices were applied, an environmental and technical cost accompanied the approach. With the completion of the flow lines and production facilities, the application of the zero flaring option became possible. The possibility to conduct zero flaring provides several attractive benefits, with at least the equivalent of 4,000 barrels of oil not flared, pollution avoidance, 50% time saving and over 50% reduction in total job costs for the field development.
Redevelopment of a Previously Uneconomic Reservoir from a Mature Oilfield, Offshore South China
Authors: Zhenghe Yan , Xiaofei Gao , Yong Yang , Zhihua Rao , Donghong Luo , Azwar Olivia , Chao Wang , Halomoan Parlindungan Monris , Bisain Amarjit Singh
Published: March 2015

After more than 20 years of intensive production in XiJiang oil field, a sand group that consists of multiple reservoirs with a thin oil column of less than 4 m and with strong bottom water drive has been revisited. Some assessments were made previously, including drilling horizontal wells with average recovery factor or only 2.3%.

In early 2013, new horizontal well drilling was initiated to reassess these reservoirs with a different approach. The objectives were to optimize the standoff between the lateral and the oil/water contact, which is very critical to well performance, by placing the lateral as close as possible to the reservoir top and to evenly regulate the downhole flow across the draining lateral.

The program was successful in reassessing the development reservoirs in the mature oil field that had previously been considered to be uneconomic through a reentry horizontal well drilling program and the implementation of the best practices in operations.

The operational practices included the precise landing and lateral placement of horizontal wells and the use of inflow control devices (ICD) for completion. Logging-while-drilling (LWD) bed-boundary mapping, with the ability to map multiple key boundaries, including fluid contact for precise well placement, was integrated with multifunction formation evaluation LWD, which provides real-time formation evaluation to optimize the ICD design for completion.

Outstanding outcomes have been observed upon the completion of the well: Producing with 1,600 BOPD with 5% water cutAchieving 56% higher cumulative incremental oil than the best previous horizontal wellExceeding the economic level threshold to develop

Comparison of new and the past well performance support the acquisition of the new field data. The successful approach, best practices, and valuable lessons learned provided a breakthrough in developing the previously unexploited reservoir.
First time Utilization of Portable Multiphase Flow Meter for Testing Offshore wells in Saudi Arabia
Authors: Alsalman Ali , Almutairi Ahmed , Alsyed Samih , Kumar Vikash
Published: March 2015

Multiphase flow meters (MPFM) have been used in the oil industry since the late 1990s to perform a rate test and ensure proper allocation from wells. On the same track, the MPFM installation and utilization in Safaniya, the world's largest offshore oilfield, started about a decade ago. Due to logistical constraints and financial priorities, not all platforms were equipped with MPFM. Moreover, Jack-up test barges with separators have been utilized in the field to test platforms without MPFM installation, platforms with faulty meters or with noncommissioned meters.

To expedite testing of non-MPFM equipped platforms and to reduce dependency on jack-up barges, a new concept of portable MPFM testing, with the MPFM equipment mobilized on a boat, was tried in Safaniya offshore field. This also came with the added benefit of testing wells on some platforms where jack-up barges could not visit due to either shallow-water depth or unsuitable seabed for jack-up rig activities.

The Portable MPFM Testing Project had its own operational and technical challenges. The main operational challenges for safe rig-up and rig-down procedures included: positioning the MPFM skid on offshore platforms, proper connection of flow-lines for rate-tests, and safe depressurization of lines before rig down. The technical challenges included: the quality of testing results, calibration of meter between platforms and acquiring accurate PVT data on the spot, and using proper centrifuge with other associated equipment.

This paper addresses in detail the initial hurdles in the above described issues and the measures taken to overcome these challenges. Over one hundred wells were tested utilizing portable meters so far and lessons learned are applied continuously. Testing with portable MPFM will be applied in the future in other Saudi Aramco fields, including both offshore platforms and onshore well-sites.
Well Testing Analysis of Horizontal Open Hole Multistage Fracturing Wells in Tight Gas Condensate Reservoirs in Saudi Arabia to Characterize Production Performance and Fracture Behavior: Case Studies
Authors: Dawood Mahdi Al , Aziz Azly Abdul , Rahim Zillur , Al-Omair Ahmed , Anisur Rahman N.M.
Published: March 2015

Horizontal Open Hole multistage fracturing (OHMSF) completion is the preferred completion to develop the tight and heterogeneous carbonate reservoir. Production data analyses and pressure transient tests are systematically and routinely conducted on these wells to determine the well productivity indices and evaluate key reservoir and fracture parameters. The OHMSF completions have been implemented since 2009 and have showed remarkable results compared to other completions and stimulation strategies such as vertical wells with single or multistage fracturing and open hole multilateral wells with maximum reservoir contacts.

This paper presents the modeling and interpretation of production and actual pressure transient responses of horizontal OHMSF wells that were drilled in both the minimum horizontal stress (σmin) direction and the maximum horizontal stress (σmax) directions to assess the production and fracture behavior. Creating transverse fractures has shown better productivity compared to the longitudinal fractures in terms of production performance, which is corroborated in the paper through pressure transient analyses (PTA) and results from field data. The paper evaluates the impact of the fracture parameters such as fracture half length, conductivity, orientation, and number of fractures on production and pressure behavior. Well testing and production analyses tools are very powerful techniques to assess and compare different types of flow regimes for horizontal OHMSF wells drilled in different azimuth directions. This paper discusses and explains the different derivative shapes captured during well tests and compares these to the simulated and theoretical models. Also, the transmissibility values obtained from the mini falloff (MFO) test following during the fracture injectivity operations are compared with the flow capacity values calculated from the PTA. Challenges impacting pressure transient responses such as high wellbore storage are addressed in the paper and proper planning and use of best practices in the PTA to obtain accurate results are discussed and presented.
Evaluation and Quality Checks to Ensure Reliability and Sustainability of Safaniyah Multiphase Flow Meters (MPFMs)
Authors: Al Muailu Husain A. , Al Yateem K. S. , Al Mutairi A. A. , Kumar Vikash , Al-Ghamdi Ahmed
Published: March 2015

Since the mid-1990s, Multiphase Flow Meters (MPFM) has evolved from a revolutionary new technology into a consolidated solution widely adopted by all the major operators worldwide. This evolution has taken place mainly due to the need for high quality measurements at low operational cost and the capability of enabling remote monitoring with ease. More than 80 MPFMs have been installed in Saudi Aramco's offshore Safaniyah field offshore Saudi Aramco. The utilization of MPFM technology goes back to 2003 thus enabling Saudi Aramco to gather the reliable production data from the field and significant knowledge of operating such equipment1. MPFMs like other devices in the field are prone to failure and therefore are subjected to regular checkups and routine maintenance. Not only the physical equipment but also the data provided by MPFM must be quality checked and calibrated periodically as part of building sound Intelligent Field Infrastructure (IFI). Therefore, to ensure a continuous flow of valid production data from the field to the desktop, several measures of data QA/QC are implemented and will be presented in this paper.

One of these measures was the establishment of a service contract with one of the major MPFM suppliers to service and maintain the integrity of the MPFM software and hardware. The objective of this case study was, therefore, to analyze the main issues related to both data quality and physical checks faced by Saudi Aramco and the service company during the last nine years of MPFM operations in the Safaniyah field. Also to share experiences and lessons learned over such an extended period of time of working with MPFM, especially in an offshore environment dealing with various operating conditions, flow regimes and an artificial lift. In this paper, the effect of field PVT variation over time on MPFM will also be discussed.
Unlock HTHP Unconventional Play in West China by Integrating Cross Domain Expertise
Authors: Zhang Fuxiang , Hao Jun , Peng Jianxin , Liu Hai , Yuan Xuefang , Qiu Kaibin , Zou Guoqing , Dong Jianyi , Judd Tobias
Published: March 2015

Reservoirs in the Tarim Basin located in Western China can exceed 6100m [20,000 feet] TVD and often classified as high- pressure high-temperature (HPHT). These sandstone formations are ultra-deep with presence of natural fractures and temperatures approaching 190°C [375°F] and reservoir pressure ranging between 110 to 125 MPa [16,000 to 18,000 psi]. The development of such resources comes with unique challenges that require a coordinated and integrated approach when drilling, collecting sub-surface data, well completions, and intervention operations. All of these tasks pose unique challenges that are often not encountered in other hydrocarbon basins. Hydraulic fracturing is a critical component to the well completion practice and is obligatory in order to maximize well productivity. This type of reservoir poses serious technical challenges that must overcome and account for the geological, geomechanical, and petrophysical interpretation. The integrated approach towards understanding the reservoir combined with the use of a novel fracture diversion technology was undertaken to ensure the maximum surface area contacted by the fracture with the reservoir and wellbore. The hydraulic fracturing design process involved the identification of intervals for multiple perforation clusters across the 200m [650 feet] reservoir section and then executing multiple stage stimulation treatments in which a fluid and proppant schedule would be pumped followed by the application of this dynamic diversion technology.

This paper will discuss this case history from a workflow perspective, introduction of this fracturing technology while using a weighted fracturing fluid with a specific gravity of 1.3, the treatment observations identified through real-time microseismic, and discuss how the better reservoir understanding enabled an improved completion strategy. The ten wells with this approach are best in class from a production standpoint when compared to the three tier reservoir potential ranking approach. Finally, the lessons learned from the first phase of this project will help guided future development activities.
Conditioning Pre-existing Old Vertical Wells to Stimulate and Test Vaca Muerta Shale Productivity through the Application of Pinpoint Completion Techniques
Authors: Forni Pablo , Bonapace Juan C. , Kovalenko Federico , Garcia Mariano N. , Sorenson Federico
Published: March 2015

One of the most promising targets for resource rock stimulation in South America is the Vaca Muerta (VM) shale in western Argentina. Because of high initial costs and also the typical reservoir information that must be acquired, it is common practice for operators to begin exploration projects with vertical wells. This is also the case for unconventional reservoirs, so initial vertical wells are used for reservoir characterization/initial comprehension and also to test the productivity of the different intervals.

Within the Neuquina basin, existing vertical wells were typically drilled to produce reservoirs below the VM source rock. Presently, with these reservoirs depleted in many areas, existing wells are often a great opportunity to investigate this upper unconventional target. Unfortunately, most of these wells are not viable candidates because they were designed to be completed through tubing. Casings and wellheads, in general, are not sufficiently strong to support pressure requirements for fracture stimulation of unconventional reservoirs.

This paper discusses the preparation of a well originally drilled in 1974 to allow for the new objective of hydraulic fracturing the VM shale to test the productivity of its different intervals. A coiled tubing (CT) assisted pinpoint completion technique (hydrajet perforating and annulus fracturing) was used to independently stimulate small intervals. To help assure that most of the reservoir was indeed stimulated, 12 single-zone fracturing stages were used for 130 meters of gross interval.

To isolate the upper (weakest) section of the wellbore, a 4 1/2-in. P-110 casing and swellable packer were installed.
Evaluation of Fracturing Fluid for Extreme Temperature Applications
Authors: Prakash Chetan , Achalpurkar Manoj , Uppuluri Ramesh
Published: March 2015

Hydraulic fracturing has remained a fundamental technique for stimulation of oil and gas reservoirs for enhanced or economic recovery of hydrocarbons from tight formations for more than 60 years. Transporting proppant downhole without any interruption and then to obtain maximum recovery of fracturing fluids are two important criteria for successful hydraulic fracturing. To achieve such objectives, the fracturing fluid should demonstrate good viscosity and complete cleanup of gelling agents. Because wells are exploited at both shallow and great depths in environments of moderate to very high temperatures and pressures, fracturing fluid selection is fundamental. Fracturing fluids prepared by crosslinking guar, guar derivatives, and other naturally occurring polymers with borate or metal crosslinkers often exhibit instability at very high temperatures. The primary reason for instability of the fracturing fluid is because strength of the bonds between the polymer chain and crosslinker decreases sharply in addition to breakdown of the glycosidic bonds between monomer units of the polymer chain beyond 375°F. Additionally, metal crosslinked bonds are prone to shear degradation, creating doubt for a successful stimulation treatment in high-temperature extended-reach wells.

To address these issues, a synthetic gelling-agent-based fracturing fluid that can work at temperatures greater than 400°F was developed. The gelling agent is a terpolymer, which can be crosslinked with a zirconium-based crosslinker. This paper discusses evaluation and performance of an extreme temperature fracturing fluid. This fracturing fluid system has sufficient proppant carrying viscosity and provides efficient post-treatment cleanup using delayed oxidized breaker. Analysis of fluid viscosity stability and delayed oxidizing breaker usage is presented in addition to performance parameters such as regained permeability and fluid loss. The study illustrates performance of the synthetic gelling-agent-based fracturing fluid at temperatures ranging from 380 to 440°F.
Successful Water Conformance Control in Horizontal Wells Using ICD Completions- A Case History Spanning Over 7 Years from Greater Burgan Field in Kuwait
Authors: Gilani Syed Zubair , Gazi Naz H. , Kotecha Rohitkumar , Shastri Mukesh Chandra , Al-Sabea Salem , Al-Humoud Jamal , Ali Badria A
Published: March 2015

Unwanted water production is a major challenge in the horizontal wells in the Greater Burgan field in Kuwait. The long lateral sections and the presence of heterogeneity lead to uneven sweep of hydrocarbons. Greater Burgan has over 60 horizontal wells to date. Initially they produced dry oil and up to the expectation but soon the water cut increased in a number of wells and avoiding water break through became a major challenge.

Burgan sandstone is a highly productive reservoir and the permeability variation is huge from less than a Darcy to a few Darcy. Thus, the horizontal wells have uneven flow profile and subsequent coning and cresting effects resulting in bypassed oil and poor recovery.

To have a better down-hole water management in horizontal wells a number of options from chemical water shut-off and isolating the toe side using packers to use of straddle packers in the middle and heel side of the horizontal section were tried. However, the use of Inflow Control Device-ICD proved to be the best option to restrict and slow down and contain the water production by creating additional pressure drop and achieve better sweep efficiency.

The first ICD completion in the Greater Burgan field and in KOC was implemented in a sidetrack well in 2007. To date the well is flowing with 45% water cut which is almost constant from the beginning for 7 years now. It resulted in a net gain of 2400BOPD from this well.

This paper will describe this case history, how the system was designed, completed, and monitored, and the successful results achieved for over 7 years. This successful use of ICDs for water conformance lead to more applications in Kuwait and will give a good understanding for the future use in other areas.
Production Logging Interpretation Challenges in Evaluating Highly Deviated Wells with Advanced ICD Completions
Authors: Espinoza Irina Baca , Vicario Roberto , Affandi Imam
Published: March 2015

In the last decade, more complex and efficient way to complete the wells has been used to maximize and optimize the production in highly deviated/horizontal-reach wells. This requires adjustments to the production logging (PL) interpretation methodology.

This paper demonstrates the complexity of PLT interpretation in highly deviated wells completed with inflow control devices (ICD) and openhole packers in carbonate formations. The addressed issues and solutions include downhole calibrations, holdup and velocity stream determination for different fluids in the production tubing and accounting for the effect of wellbore inclination and inflow distribution from several fluid entries per single isolated zone. Production logging is performed using standard and advanced tools, such as multiple array modules and pulsed-neutron tools.

The ICD pre-installation design is strongly based on the availability of a permeability profile, which is usually derived by static data logging interpretation. Consequently, the second objective of this paper is to compare the initial permeability profile with the permeability profile derived by interpretation of dynamic data such as PL.

The results from production logging analysis demonstrate that the standard method of PL interpretation could be applied for advanced ICD completion evaluation by taking into consideration several factors such as calibration, well deviation and associated holdup, flow regime and zonal inflow distribution for multi-ICD inlets. The applicable software used for comparison of pre-design completion static-derived productivity index (PI) is contrasted with dynamic-derived PI from production logging tool (PLT). The pressure regime in the wellbore and annular pressures behind ICDs were used as additional input for better understanding the fluid flowing nature and investigation of the productivity index.

The confirmed continuous permeability profile enables grid refining in a reservoir simulation study and better planning of the well production performance. The technique and solutions described in this paper can be widely used to evaluate and improve carbonate reservoir characterization for every deviated well completed with inflow control devices.
Formation Testing While Drilling Enables Successful Pressure Data Acquisition in Depleted Reservoir Zone Not Previously Possible with Wireline Logging in Kuwait: A Success Story
Authors: Al-Khaldy Meshal D. , Safar Ahmad , Kumar Sanjeev , De Santanu , Dutta Abhijit , Makki Ahmed , Al-Shammari Altaf , Samie Mohamed Abdel , Ibrahim Ahmed A. , Warraky Mohamed , Abdulkarim Anar
Published: March 2015

Formation testing while drilling (FTWD) proved to be of great value to the asset team at Kuwait Oil Company (KOC) while recently drilling a deep, deviated well to target the Zubair sands.

The deviated 8-1/2-in. hole section of the well had been planned to cut through more than 1,100 ft of true vertical thickness containing multiple reservoir units with varying pressures, lithologies, and formation characteristics, which posed a great risk for drilling operations and required the use of relatively high-density mud to maintain wellbore stability. The presence of highly depleted reservoir zones in this mature reservoir resulted in a challenging pressure overbalance in excess of 4,800 psi.

Attempts to measure formation pressure in previous vertical offset wells in the same depleted zone in the same field/environment using wireline formation testers yielded either unsuccessful or erroneous results, indicating a tight formation, which conflicted with previous production and coring data available that suggested high-permeability sands were present. The high overbalance was suspected to be the primary cause of formation damage and blockage resulting from solids content in the drilling fluid and longer exposure time. KOC has historically opted for taking pressure points in wipe mode rather than dynamically while drilling in open holes containing unstable Zubair shales. Moreover, a large number of planned pressure points with the drilling assembly cutting across various sand zones posed several challenges.

The asset team had plans to exploit such depleted zones through future horizontal drilling; however, an up-to-date pressure measurement was required to assess feasibility.

This paper discusses the planning, design, and execution of this well. It also focuses on the use of the FTWD solution alongside other logging-while-drilling (LWD) and rotary steerable assemblies to overcome the drilling challenges and successfully follow the planned data-acquisition program to optimize the completion and production strategy and discusses how the solution affected the decision making for future wells.
Short Radius Horizontal Sidetrack into Sandstone Reservoir and Completion with Inflow Control Device & Zonal Isolation-A Case Study
Authors: Shastri Mukesh Chandra , Gazi Naz H. , Kotecha RohitKumar , Al-Enezi Hamdah , Al-Azmi Khalid Humoud , Gilani Syed Zubair , Saradhi Vijay , Vijayvargiya Vivek , Al-Sabea Salem
Published: March 2015

For managing limited resources, short and medium horizontal sidetracks offer feasible options for non-conventional well work-over. Sidetracking into horizontal lateral is preferred over other options due to improved productivity.

Many short-radius horizontal sidetrack wells with high Dog Leg Severity (DLS) have successfully been drilled and completed with Inflow Control Device (ICD) in carbonate reservoirs in the Middle East, however in case of sandstone reservoirs it poses a great challenge.

This technology, which envisages short and medium radius horizontal sidetrack from existing well bore for optimal utilization of asset, was applied in a sick well from Greater Burgan field in Kuwait. A window was cut in existing 7″ casing and 6 1/2″ drain hole was drilled up to 6016′ MD. Initially this well was planned for sidetrack into main sand with maximum 35° DLS and feasibility study was done. But due to mechanical complications during work-over it was kicked off shallower, cutting shale above main sand, and the final well trajectory was maintained with maximum 23° DLS. The horizontal lateral was completed with 4 ½″ ICD and seven numbers of mechanically set open-hole packers for zonal isolation.

The well completion with this technology with high DLS in a sandstone reservoir is probably the first time in the world. This paper will describe and present the case history of the application of this technology; the challenges faced during work-over, drilling of the drain hole with sand-shale contrast and the smooth running of completion assembly with high DLS.

After work-over the well was put on production in May'08. As on date it is flowing with 45 -55% water cut which is almost constant since then, resulted in a net gain of 2400BOPD from this well. This successful sidetrack leads to more applications for exploiting heterogeneous reservoir in the Middle East Region.
Management of E&P Data using Enterprise GIS System
Authors: Puripanda Naresh Kumar , Kumar K , Anaisi Abdulla Al , Prasad Vineet , Sowayed Mohammed
Published: March 2015

Exploration and Production industry over a generation of time have invested heavily on G&G, Production and Engineering data and their relevant applications. The whole data is generated and utilized right across the business value chain however; many organizations struggle to manage their data effectively and how well this vital geographical information is integrated and analyzed can be critical to the success of any organization.

Petrochemical giants have embraced GIS as a means of detecting oil and gas resources and tracking oil spills. At its core, GIS is a visual database that is transactionally updated. It makes use of data creation workflows that harness the underlying database, using it to produce different views depending on what users want.

Bapco has established an Enterprise GIS System (Bahrain Petroleum Company's (Bapco) Integrated E&P Digital Oil Field) which helps in accessing, monitoring, analyzing, organizing and managing data related to all aspects of Bapco's business units in an effective manner. This is one of the main gateways to a wide range of E&P data and is much more than a visualization and analytical tool. It is highly secure, strongly integrated and coupled with many of the Exploration & Production databases and applications. This system facilitated preparation of the roadmap for better petro-technical data and information management initiatives, particularly to control data that are extensively volume-driven as is the case with seismic, well logs, production, geological and reservoir simulation models and time-critical or real-time data. One can use GIS to map anything and to combine anything mapped with further data to see the patterns. GIS helps change how we think and behave. People see things differently, and this enables them to approach problem-solving in new ways.

This paper discusses the approach adopted by Bapco in managing E&P data using Enterprise GIS System.
Horizontal Reentry Wells in Khafji Joint Operations: From Unachievable to a Benchmark of Success
Authors: Al-Fawwaz Abdullah , Muheeb Mohammed , Osman Ahmed , Al-Ghazzawi Ayman , Al Fakih Abdulqawi , Azher Mohammed Mushtaq
Published: March 2015

Khafji Joint Operations (KJO) is operating a key oil-producing field. This field has been developed extensively via horizontal drilling technologies for the past two decades. With excessive time and costs required for new offshore structure installation, the utilizing of the existing wells to drill re-entry horizontal wells became imperative and economical solution for further field developing, while minimizing the cost per foot required for well delivery.

Horizontal Re-entry operation in KJO has always been deemed totally undoable due to the fact that the 7 inch production liner in most of the old wells was tied back and cemented to surface. Hence, re-entry sidetrack operation would not have enough conventional casing strings options to allow the drill ahead to reservoir while having enough mechanical barriers to isolate the unstable shale zones. Also, slimming down the well design could not be a favored option as it does not accommodate the geo-steering, formation evaluation and completion requirements; which are essential for placing and producing the re-entry wells within KJO reservoirs.

To enable these re-entry wells, the Khafji drilling teams have performed a comprehensive study and risk assessment to re-define the strategy for drilling these horizontal re-entry wells. The new strategy divided the targeted re-entry wells into three main categories based on the challenges and complexity underlying each well. Each category was then assigned key enabling technologies in mud, drilling systems, optimum drilling practices, and completion techniques. These strategies along with enabling technologies were successfully implemented in a new horizontal re-entry campaign in KJO and have managed to deliver eight of these challenging wells during years 2013 and 2014.
Novel Technique for Reciprocating Compressor Cylinder Leak Detection
Authors: Hastings M. , Koop L.
Published: March 2015

The polytropic exponent function is an existing proprietary monitoring function that automatically detects reciprocating compressor cylinder leaks. It uses dynamic pressure and corresponding calculated volume values at, for example, one degree intervals, to calculate the polytropic exponent value of the measured compressed and expanded gas within each cylinder end. Deviations of this calculated exponent compared to the known polytropic exponent of the gas properties gives an indication of a cylinder leak due to a specific valve, the seal, the piston rings or even a crack in the cylinder liner. A non-proprietary version of the polytropic exponent function has been developed and tested on a gas re-injection reciprocating compressor and it can lend itself to be further refined to make it more independent of the gas properties.

The need for reliably detecting reciprocating compressor cylinder leaks is paramount as the cylinder, and more specifically the valves, account for the majority of the maintenance. PV plots are often used to determine cylinder leaks but these currently cannot be easily monitored to alarm limits automatically and require specialists to analyze and interpret the results. Moreover, the gas properties are also needed to generate theoretical PV plots that can be compared to the actual plots and there are many installation errors that can “distort” the PV plot. The polytropic exponent function provides automatic monitoring capability without requiring much specialist expertise, but it is still currently a proprietary solution and requires intimate knowledge about the gas properties. This paper focuses on the refinement of the existing polytropic exponent function.

The new refinement is currently being tested on a gas re-injection reciprocating compressor at an offshore project. No leaks have been detected up to now, but results show a stable, reliable function that is well suited to monitoring applications, although with limitations.
Completion Optimization for Unconventional Reservoir
Authors: Hamid Osman , Rahim Zillur , Alshakhs Munther , Mubarak Ahmed , Fisher Kevin , Ba-wazir Omar A.
Published: March 2015

The success in producing from unconventional reservoirs is made possible by horizontal drilling and reservoir stimulation through multi-stage hydraulic fracturing along the laterals. Although hydraulic fracturing techniques have been widely used for unconventional shale gas stimulation, a considerable percentage of perforations do not contribute to production. Reservoir characterization and computation of completion parameters are essential for effective completion design to improve staging and perforation placement.

Challenges in hydraulic fracture design are the proper placement of fracturing ports or perforations and location of isolation packers due to the large variability of fracture gradient, mechanical and reservoir properties, and petrophysical characteristics existing along the lateral. Industry experiences show that injection pressures required to fracture the formation (fracture gradient) oftentimes vary significantly along a well, and there can be intervals where the formation cannot be fractured successfully by fluid injection due to the existence of high in-situ stress.

Geomechanical and Petrophysical evaluations providing rock anisotropy and anisotropic stress properties along the wellbore play a fundamental role in completion and hydraulic fracture design. In this paper, geomechanical and petrophysical properties from open-hole logs and sonic anisotropy evaluations have been integrated to compute reservoir quality and completion quality. Intervals with similar properties are then grouped in a manner to better understand and optimize hydraulic fracture design and operations. This procedure is applied in a borehole within a potential shale-gas reservoir targeting the hot shale facies formation in Saudi Arabia resulting in a successful completion optimization and hydraulic fracture performance.