Al-salali, Yousef Zaid (Kuwait Oil Company) | Ayyavoo, ManiMaran (Kuwait Oil Company) | Al-ibrahim, Abdullah Reda (Kuwait Oil Company) | Al-Bader, Haifa (Kuwait Oil Company) | Duggirala, Vidya Sagar (Kuwait Oil Company) | Subban, Packirisamy (Kuwait Oil Company)
This paper discusses the outstanding performance achieved in a deep HPHTJurassic formation drilled using Potassium Formate based fluid. This paper alsodescribes methodology adopted for short term testing and stimulation of anexploratory well and finally the field results.
Drilling and completion of deep Jurassic formations in the state of Kuwaitis generally done with Oil Base Mud (OBM) weighted with Barite. Duringdrilling, barite causes significant formation damage to the carbonates withnatural fractures and it is essential to stimulate the well to evaluate thereal reservoir potential. Formation damage is usually treated with matrix acidstimulation, however barite does not respond to acid. Kuwait Oil Company (KOC)was in search for an alternative drilling fluid causing relatively lessformation damage and also responds to remedial actions. Potassium Formate brinewith suitable weighting agent to achieve sufficient mud weight around 16ppg wasselected for field trial in one of the exploratory wells. Formate based brineis a high-density Water Base Mud (WBM) which maintains rheological stability athigh temperature and minimizes formation damage.
Last 2,000 feet in 6" hole section of 18,000 feet well was drilled using15.9 ppg Potassium Formate WBM. During short term testing, acid wash alone wassufficient to remove the formation damage and productivity has tripled which isunlikely in case of wells drilled with OBM.
This case study shows how Potassium Formate based mud enhanced theproductivity and reduced the testing time and cost. Based on the successfulfield test results, it is planned to drill future Jurassic deep formation withPotassium Formate based fluids in future.
The North Kuwait Jurassic Gas (NKJG) reservoirs are currently under development by KOC with assistance from Shell under an Enhanced Technical Services Agreement (ETSA). The fractured carbonate reservoirs contain gas condensate and volatile oil at pressures up to 11,500 psi with 2.5% H2S and 1.5% CO2. This paper describes the planning and implementation of a Well Integrity Management System (WIMS) that allows the safe management of the wells that are being drilled in this hazardous environment.
The wells are designed and constructed in accordance with KOC standards and on transfer of ownership from Deep Drilling Group to Production Services Group have their integrity managed under WIMS. The system is a structured process, relating the frequency and extent of routine monitoring and testing to the particular risks associated with the wells. Compliance with WIMS requirements are routinely reported so that all are aware of the current state of well integrity. WIMS is initially managed through simple spreadsheets and during 2012 is being integrated into KOC's Digital Field infrastructure.
Initially, WIMS has been applied to the range of wells ‘owned' by Production Services Group and tests currently carried out by Well Surveillance Group under PSG's direction. In order to realise the full assurance of safe operation the scope of WIMS application is being extended to the full well population, including suspended wells, and the full range of tests required.
Implementation of WIMS will allow KOC (NKJG) to be able to state that ‘our wells are safe and we know it'.
A two-year-long field study was conducted by ConocoPhillips Alaska, Inc. andPND Engineers, Inc., at Kuparuk in Alaska's arctic North Slope region. Thestudy verified that pipe piles can be directly driven into predrilled pilotholes in frozen ground, without requiring thermal modification of thepermafrost. The traditional "drill-and-slurry" method of permafrost pileinstallation involves hanging piles in an oversize hole and backfilling theannulus with a sand/water slurry. Vibratory driven pile installation isconsiderably more efficient with large benefits in installation time, expenses,and safety. Both methods require an adequate adfreeze bond for pileperformance. The objective of this testing program was to determine whetherdespite great benefits in installation efficiency the vibratory driven pilewould perform adequately. Twelve 12.75-inch-diameter steel pipe piles wereinstalled in permafrost in the Alaskan arctic; eight piles were installed inice-rich sandy silt and four piles were installed in a frozen gravel soil.Piles were loaded in tension for six different durations ranging from five daysto six months at loads varying from 35 kips to 145 kips. At the completion oflong-term testing, the test piles were unloaded, rested, and then loaded tofailure to characterize the adfreeze short-term strength. Pile load anddisplacement were continuously recorded with electronic displacement and loadtransducers. Subsurface soil temperatures were also monitored. Collected datawas used to characterize long- and short-term pile velocity as a function ofload and adfreeze temperature. Experimental results were compared to currenttheoretical and empirical performance.
Efficient and robust phase equilibrium computation has become a prerequisite for successful large-scale compositional reservoir simulation. When knowledge of the number of phases is not available, the ideal strategy for phase-split calculation is the use of stability testing. Stability testing not only establishes whether a given state is stable, but also provides good initial guess for phase-split calculation. In this research, we present a general strategy for two- and three-phase split calculations based on reliable stability testing. Our strategy includes the introduction of systematic initialization of stability testing particularly for liquid/liquid and vapor/liquid/liquid equilibria. Powerful features of the strategy are extensively tested by examples including calculation of complicated phase envelopes of hydrocarbon fluids mixed with CO2 in single-, two-, and three-phase regions.
Al Hammadi, Ibrahim Thani (Abu Dhabi Co. Onshore Oil Opn.) | Aly, Samir Handak (Abu Dhabi Co. Onshore Oil Opn.) | Khan, Muhammad Navaid (Schlumberger) | Gurses, Hakan (Schlumberger Middle East SA) | Baslaib, Abdullah
Oil and Gas industry began to take attentiveness in developing Multi Phase Flow Meters (MPFM) in the early 1980s as the remote data access and improved performance with more compact mobile testing systems were the key features of the required technology. MPFMs were initially used in offshore industry; however, presently their applications are prolonged to land and even subsea installations.
For over ten years, Abu Dhabi Company for Onshore Oil Operations (ADCO) has been using MPFM in several oil fields and concession areas. Being relatively the furthermost recent developed field, clustering options, and full application of i-field concept including collaborative environment (CWE); North East Bab (NEB) Asset is crowned for being the frontrunner in adopting the up-to-date technologies among other ADCO Assets.
NEB full field development was custom-built in 2005. Fifteen (15) number of conventional three phase test separators were put together for reservoir surveillance and production testing requirement and were lately refurbished and upgraded with Coriolis and V-cone meters rather than originally installed turbine meters. During this period, two portable MFPMs were contracted out in order to achieve the annual testing KPI and prospect was taken to validate the Coriolis and V-cone meters of the refurbished test separators using MPFMs'. This project facilitated instituting better communication protocols along with comprehensive collaborative workflow between NEB Asset and the service provider that resulted in successful completion of the revamping project. This as well had tremendously encouraged ADCO (NEB Asset) to permanently include MPFM flow metering applications in the upcoming future developments.
This paper aspires to share the valuable experience gained by utilizing the MPFM in NEB Asset for different flow metering applications, and to establish the technology adoption guidelines for other field operators.
As the severity of sour drilling applications has increased the need for drill stem materials resistant to Sulfide Stress Cracking (SSC) has accelerated. This is especially true in the Middle East with some of the most severe H2S environments in the world. Sour service drillpipe, built with SSC resistant tubes and tool joints, has been available for some time. The friction welds joining the tubes and tool joints were not SSC resistant. This has been acceptable for many sour applications since the weld is not the high stress area of the drillpipe and because the operator has some control over the environment through the drilling fluid properties and additives. As more severe H2S environments were identified for exploration, it became apparent that a fully SSC resistant drillpipe system including the friction welds was necessary. This paper presents the successful development of SSC resistant friction welds for critical sour applications. It describes the engineering and manufacturing philosophy, laboratory testing procedures and results and applications for the SSC resistant drillpipe. Since NACE MR-0175 does not cover friction welds the engineering team developed unique and innovative criteria and testing procedures. A new patent pending four point bending test procedure and fixture were develop that employed unpolished samples that represent the surface finish of the product in service, unlike polished samples typically used in NACE TM-0177 testing. This paper provides background information on the evolution of sour service drillpipe and reviews case histories where sour service drillpipe has been successfully used including the new pipe with SSC resistant friction welds. A preview of some vital planning considerations for an upcoming world-class ERD well in Saudi Arabia with high H2S concentrations is also included. The paper can benefit drilling engineers involved in critical sour drilling operations in the Middle East and other world regions.
Sour Service Drillpipe
The drillpipe assembly incorporates a tool joint that is typically manufactured from a forging and a friction weld that attaches the tool joint to the upset of the pipe body. This is the same manufacturing configuration that has been employed on drillpipe for decades and has been adapted to incorporate materials that resist SSC for critical sour applications. The manufacturing technology for critical service drillpipe has evolved significantly in the last several years. Major advances relating to pipe specifically developed for use in areas with significant H2S content have been realized.
Sulfide Stress Cracking (SSC) due to the presence of H2S gas in the downhole drilling environments has led to the development of sour service drillpipe, which is engineered to have resistance to SSC. Previously available sour service drillpipe was comprised of an SSC resistant upset to grade tube and tool joint. The friction weld areas that are used to join the tool joints to the upset ends of the tubes were not manufactured for resistance to SSC.
The produced fluid of an oil field located in the Eastern Province of Saudi Arabia contains relatively high levels of H2S. A pilot test was conducted by Saudi Aramco to install a wireless gas detection system along an oil pipeline in this field. The pilot test objectives include:
The piloted system includes six wireless sensors separated at an equal distance along a 2 km oil pipeline. The sensors communicate wirelessly with a gateway receiver located in a shelter at a producer site. The wireless gateway is integrated with an existing Supervisory Control and Data Acquisition (SCADA) system by connecting it serially to a Remote Terminal Unit (RTU). Accordingly, the sensor's measurement and diagnostic data is monitored by the operators at their console in the control room. The same data is also accessible to the engineers at their desktops for real time monitoring and long-term archiving purposes via the OSI PI system.
The test results of the year-long pilot indicated that the gateway receiver demonstrated very high reliability and availability since it had no failures during the test period; however, initially some of the wireless sensors had experienced minor but recoverable communication errors.
This paper describes the details of this pilot test and discusses the difficulties encountered during the project's testing phase along with the actions taken to mitigate such problems, and subsequently improve the overall reliability and availability of the wireless communication.
All the offshore facilities for most oil and gas companies are matures now as most of the offshore platforms were constructed from 1960 with life time over 50 years. Therefore, most of the owner companies start to perform a rehabilitation projects for the structural, mechanical, piping , electrical and all the other facilities to maintain then to have a safe longer life and to comply with the recent standard and technical practice. Therefore, the project strategy for this type of brown field project is totally different than the applied strategy for green field for a new offshore platform.
In these type of projects there are many stakeholders to manage that influence the project as the endeavor users are usually have a higher expectation from these projects, In addition to that the new facilities will use a new technique match with the up to date technology.
This paper will present the nature of project management for this type of projects and the challenges that faces the team along the project life cycle. The new approach for the whole building commissioning system technique will be discussed as a solution that cover the pitfall for applying the normal project management procedures in the brown field for oil and gas projects.
Existing Management Strategy
In most oil and gas projects, the owner creates a separate organization for the project. The team will be formulated from the project manager (PM), and hire an engineering firm (EF) to do the design activity under the supervision of the owner engineering team and the construction manager (CM) will be responsible to the construction phase.
In most cases, the operations department is responsible for the operation phase, as in this phase the operations/productions will have full authority and responsibility to operate the project after the commissioning and start-up phase.
In case of rehabilitation project for the existing facilities which is called the brown field project is usually complicated than the green field as there are more changes and strange situation face the project team as the equipment are not still exist in the market and the compatability of the upgrade system with the existing system. In addition the familaritioes of the operations team to the old system so it needs a management of change approach.
In our case study the project is well organized and all the document , procedure and select of the member is match with the PMP book guide and fulfill the total quality management requirement. However as the operation are the stakeholder so they are sharing in the scope of work and also involoved in every meeting for follow up and provide their feedback and define the requirement.
Ladmia, Abdelhak (ADMA) | Al-Marri, Faisal (Abu Dhabi Marine Operating Co.) | Hussein, Mohamed AlSalam (Abu Dhabi Marine Operating Co.) | Al-Neaimi, Ahmed Khaleefa (Abu Dhabi Marine Operating Co.) | Khalil, Hassan Ibrahim (Abu Dhabi Marine Operating Co.) | Ibrahim, Mohamed Elsayed (Abu Dhabi Marine Operating Co.) | Santhanam, Kalakad S. (ADMA-OPCO) | Abu Chaker, Hicham (ADMA-OPCO) | Al-Sheikh, Hosny (ADMA-OPCO) | Moslem, Samaai (ADMA-OPCO) | Al Marasy, Hatem (Schlumberger) | Salasman, Alan
Several wells in Offshore field Abu Dhabi are unable to flow due to Low Well Head Flowing Pressure LWHFP and also other wells are unable to flow due to Asphaltenes deposit causing a restriction under certain conditions of pressure and temperature even after a remedial job using a mixture of Xylene-Diesel (20% / 80%). However the well in this case, Well-1, has a combined problem being unable to flow with both LWHFP & asphaltenes deposit.
In some applications the field layout and operation conditions also cause restrictions in production from the producing wells. The use of the technique of re- perforation using a 2'' Premium Deep Penetrating Gun plus additional acid stimulation with a coiled tubing unit CTU to remove formation damage through double casing is a cost effective way to lower the skin and boost the flowing pressure of LWHFP wells.
Remediation of LWHFP often requires a complex and time consuming intervention (Acid Fracturation, Side Track etc.) with relatively low success rate, which is perhaps why thousands of wells globally currently exhibit LWHFP and cannot be produced due to high line pressure (HPP) in the gathering pipelines.
The objective of this paper is to highlight the challenging yet successful techniques implemented to remediate restricted tubing due to asphaltenes precipitation and restore productivity in the off-shore Field, Abu Dhabi. These jobs are done rigless to aid efficiency and keep cost down and have been successful at getting the wells back on line.
Al Braiki, Saleh (ZADCO Petroleum Co) | Al-Sawadi, Obadah Saleem (Zakum Development Co.) | Afzal, Muhammad (Zakum Development Co.) | Odeh, Nadir M.M. (ZADCO Petroleum Co) | Yar Khan, Naeem Shahid (Zakum Development Co.) | Al Hosani, Abdulla Hasan (ZADCO Petroleum Co) | Bani Malek, Ahmed (ZADCO) | Yousef, Anwar (Halliburton Co.) | Faruqi, Shamim (Halliburton)
In ZADCO's giant offshore oilfield, the Surface-Controlled Downhole Safety Valve (SC-DHSV) system of some oil producers failed to operate. Thorough investigation revealed that SC-DHSV landing nipple sealbore damage was the root cause of failure. The failed SC-DHSVs were temporarily replaced with A-3 Storm Choke Valves.
The conventional solution to restore the integrity of a failed SC-DHSV was the workover. However, efforts were made in identifying a viable rigless solution by thoroughly reviewing the available options and as an alternative, special oversized B-Type seals were chosen to substitute the existing conventional V-Type packings that failed to seal in said valves.
To ensure safe field implementation, a risk assessment was conducted followed by successful yard testing. Field implementation was successfully completed by utilizing conventional slickline unit which saved significant time and cost. A standard SC-DHSV was redressed with the oversized B-Type seals, set in the landing nipple and functioned normally. The redressed SC-DHSVs were routinely tested during the following year with no concern reported. The successful implementation was documented and is recommended for future use in similar cases.
Well integrity, Downhole Safety Valve (DHSV) System, DHSV Landing Nipple Polished Sealbore Area, Risk Assessment, Workover, Rigless Application.