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'.
Ilyas, Asad (MOL Pakistan Oil & Gas Co. B.V.) | Arshad, Safwan (MOL Pakistan Oil & Gas Co. B.V.) | Ahmad, Jawad (MOL Pakistan Oil & Gas Co. B.V.) | Khalid, Arsalan (Schlumberger) | Mughal, Muhammad Haroon (Schlumberger)
This paper describes the challenges in determining average reservoir pressures in multi-layer completed wells during the span of their production period. The wells with single production tubing and get comingled flow from different reservoir layers exhibit complex down holeflow profiles. Therefore, it becomes difficult to acquire average pressures of each producing layer separately. Production log data can be utilized in these kinds of wells to calculate average individual layer pressures with the help of Selective Inflow Performance (SIP) technique for better production allocation and also to monitor pressure depletion effects with time.
The SIP provides a mean of establishing the IPR for each rate-producing layer. The well is flowed at several different stabilized surface rates and for each rate, a production log is run across the entire producing interval(s) to record simultaneous profiles of downhole flow rates and flowing pressure. Measured in-situ rates can be converted to surface conditions using PVT data. Although SIP theory only applies to single phase flow, the interpreter can restrict the IPR's computations to a particular phase; only contribution of the selected phase will be taken into account. To each reservoir zone corresponds for each survey/interpretation a couple [rate, pressure], used in the SIP calculation. The different types of IPR equations can be used for SIP interpretation: Straight line, Fetkovitch or C&n, and LIT relations. In the case of a gas wells, the pseudo pressure m(p) can be used instead of the pressure "p?? to estimate the gas potential. Although SIP is a useful technique to estimate average reservoir pressure in multi-layered system, but it has some limitations under certain circumstances.
The Selective Inflow Performance (SIP) technique has been implemented on some of the producing wells in north o f Pakistan. These wells have been completed in multiple producing reservoirs. Initially all these reservoirs were tested separately (with DST) to estimate their reservoir pressures and other parameters. However, due to adapted completion strategy, the producing layers were comingled with the option to monitor each layer's pressure depletion with the help of SIP technique in future. As per reservoir surveillance activity, Production logs are run on routine basis by utilizing SIP method and the same has been utilized for reservoir management and for simulation model updates.
Sherwani, Waseem Akhtar (Eastern Testing Service (Pvt) Limited) | Qureshi, Imran (Eastern Testing Service (Pvt) Limited) | Khattak, Kifayatullah (Eastern Testing Service (Pvt) Limited) | Ali, Abdul Salam (Eastern Testing Service (Pvt) Limited) | Ali, Syed Dost (Pakistan Petroleum Limited)
Well control is the management of the hazardous effects caused by the unexpected well release. In a production well, downhole safety valve and X-mass tree are considered the main barriers against the well release in the event of a worst case scenario surface disaster. Inadequate risk management and improperly managed well control situations cause blowouts, potentially resulting in a fire hazard.
This paper describes a case history of a production well where a tubing string was eroded severely during production phase. The problem was detected while attempting to retrieve the separation sleeve in the long string which was not accessible at the required depth. Downhole camera indicated that 90% of the long string had been eroded and remaining 10% is connected with the flow coupling. Thus, full workover job was required to replace tubing strings. However, the lack of well control barrier in the tubing to prevent uncontrolled flow of hydrocarbons prior to blowout preventer (BOP) installation for the workover was a serious safety concern.
Introduction of Nippleless Tubing-Stop Plug technology provide an effective, safe and economical remedial solution to the problem.
As part of well control standard, double barrier policy is always maintained on the well to avoid unwanted and uncontrolled flow from the well. Before any work over, the well must first be killed as a first well control barrier. A second barrier is required to prevent communication from the wellbore to surface once the wellhead is removed. Tubing plug is an effective second barrier used to isolate the wellbore pressure from tubing.
NIPPLELESS PLUG TECHNOLOGY DEPLOYMENT
In the past, the tubing plug's lock systems have been designed in which landing nipples or profiles are provided along the tubing string's interior surface, and wherein a lock/ plug will be placed in the nipple or profile. However, placement of a lock of this type is limited to those points along the string at which an appropriate nipple or profile is located. In cases where tubing string is damaged or eroded where nipple or profile is no longer usable, the common tubing plug can no longer be a barrier device.
Introduction of "Nippleless?? plugs addressed this issue because they do not require the presence of a nipple or profile to be set within a string. Nippleless plug offer the capability to set plugs at any depth or point within well.
Stationkeeping in ice-covered waters has become a large area of interest forresearch and development in light of heightened interest in Arctic oil and gasexploration. The performance of Dynamic Positioning (DP) control systems forstationkeeping purposes in ice conditions is a difficult challenge fornumerical modeling assessment. Given that full-scale validation data for DP inice operations is often scarce, physical modeling of stationkeeping in iceoffers the best method for assessing the performance of dynamically positionedvessels in these conditions. A series of model tests carried out at theNational Research Council of Canada's Ice Tank facility in August and Septemberof 2011 attempted to observe the effects of various managed ice conditions(i.e. ice floes which have been broken into manageable pieces by an icebreaker) on DP performance. Results from these tests are discussed. Ofparticular interest in this study is the observation of non-linear effects ofvarying ice conditions on DP performance. The use of machine vision-based dataproducts as potential estimators of ice loading is discussed. It is concludedthat simple statistical observations of these conditions will be unable tofully characterize the effects of various ice parameters on performance, andthat investigation into more advanced data products available from machinevision systems may be able to aide in characterizing these effects as well asin the development of models capable of predicting ice loads.
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.
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.
Well testing on remote unmanned wellhead platforms (WHPTs), especially those with marginal wells is a challenge. On some of these remote WHPTs, currently well testing is done using a test separator installed on a supply boat. This method of testing the wells involves lot of manual intervention and is a time consuming activity with various activities which are sometime quite hazardous. In view of new field developments plans to increase production and to have more frequent and longer duration testing, an initiative was taken to look at the option of installing multiphase flow meters (MPFMs) on such well head towers which do not have well testing facilities. Accordingly, one MPFM each was installed on separate WHPTs.
By installing the MPFMs, ZADCO is now able to test these wells more frequently and for longer durations.These trial installations have been very successful as verified by the comparison of test results of the MPFM vs. Test Boat vs. Reservoir simulations. The success is not only in terms of testing but also proved beneficial in terms of saved man-hours and increased safety. Safety is increased and man-hours spent are reduced by avoiding all theconection / disconnection oftemporary manual piping from the boat to the well head tower.
This has encouraged ZADCO to embark on an exercise to install MPFMs on all those WHPTs which do not have a test separator and also to install MPFMs on those WHPTs where the existing test separators have become undersized due to the increase in production profile.
This trial use of MPFM in addition to providing very satisfactory test results in line with ZADCO testing requirements also has benefitted in various other ways as follows:
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.