T his second part of an article about a large 3D VSP survey in Abu Dhabi describes the interpretation effort which quantifies the value that a 3D VSP seismic image can bring when supplementing even a 640-fold, highresolution surface seismic volume.It is understood that for recovery to be optimized and bypassed resources to be minimized, especially in later stages of field production, more accurate models of a reservoir's architecture and characteristics are needed. This first 3D VSP survey in Abu Dhabi characterized details of the reservoir that could not be derived from surface data or well-log data alone. The higher-quality, higher-resolution images made it possible to map detailed stratigraphy and important but previously unknown faults. The improved structural map and updated geologic model were verified by wells drilled inside the 3D VSP image areas. The effect of receiver array length and source effort on VSP qualityTo better understand the value in acquiring 3D VSP data with long borehole receiver arrays, processing tests using a conventional 12-level receiver configuration were conducted by using a subset of the 126-level VSP data. Using the same statics, velocity model, and other relevant processing parameters developed for the 126-level array data, a 3D VSP image was produced with data from only 12 geophone levels. Figure 1 compares VSP common depth point (VCDP) gathers at different offsets between the 12-and 126-level data. At an offset of 400 m, both the 12-and 126-level gathers show well organized energy from primary events. Good VSP images up to 400 m away from the well should be possible with both data sets. At the longer offset of 700 m, there does not appear to be any indication of primary events on the 12-level gather. However, due to higher fold, primary events are clearly visible on the 126-level gather. This result suggests the reason; in 12-level walkaway VSPs, it is difficult to image distances greater than 500 m from the wellbore, even though offsets up to 4 km

A mixture of Nitrogen and hydrocarbon gas was used as a cycling gas in a large rich gas condensate reservoir to maintain reservoir pressure and thus prevent condensate drop-out due to pressure decrease below the dew point pressure. The objective of using Nitrogen gas is to partially replace some of hydrocarbon injection gas, which has a high demand for Abu Dhabi domestic consumption. This paper presents the plan, implementation, results and analysis of an intensive reservoir monitoring program, which was conducted to monitor the Nitrogen injection and production. Additionally, the paper discusses lessons learned from the Nitrogen injection, inferences reached, and corrective actions taken. The Nitrogen injection was started as a Mixed Case (MC) injection, where a mixture of Nitrogen (~20%) and hydrocarbon gas (~80%) was injected in all existing injectors across the entire reservoir for a period of three years. The plan was to stop the MC injection and apply a Pure Case injection (PC), which consists of injecting only pure Nitrogen in the North West area of the reservoir. The objective of the PC injection is to localize the Nitrogen injection to be able to apply Nitrogen removal technology in a specific part of the existing surface facilities whenever high Nitrogen production is reached. Monitoring the Nitrogen production relies mainly on an intensive gas composition sampling and analysis, which have been conducted quarterly for all gas producers, in addition to other surveillance activities of the intensive reservoir monitoring program. The Nitrogen monitoring results and analysis of the MC injection showed Nitrogen breakthrough in many wells with increasing Nitrogen production trends. Different analytical techniques were applied to evaluate and predict the Nitrogen breakthroughs. Due to the unavailability of surface Nitrogen removal facilities and the increase in Nitrogen production during the MC injection, a Nitrogen risk assessment study supported a recommendation to stop the MC injection and continue cycling with dry hydrocarbon gas only as before. Also, it was decided to delay the planned PC injection for more evaluations and studies.

Abu Dhabi Company for Onshore Oil Operations (ADCO) undertook a two-well 3D VSP pilot project in 2007. Because it was acquired concurrently with a high-resolution wide-azimuth surface seismic survey, it was at the time the largest 3D VSP ever recorded. The project consisted of four main parts: acquisition, processing, interpretation, and quantifying value. In part 1 of this paper the acquisition and processing of the 3D VSP is described with an emphasis on the lessons learned. Significant advances in processing are described that demonstrate how larger 3D VSP images with better amplitudes and structural preservation can be produced. In part 2, the results of the 3D VSP interpretation and economic evaluation effort are described and illustrate different ways that a VSP image can help characterize a hydrocarbon reservoir.

ADNOC took up the challenge to drill, test and produce the highly sour HPHT gas reservoirs with +30% H2S and 10 % CO2 in brown field. The objective of the appraisal program was to gain valuable reservoir data by drilling and then testing the highly sour wells in order to finalize the facilities design and full field development plans. Before drilling the wells in the high sour environment, an extensive safety review of the area, emergency H2S zones, rigs technical capabilities, equipment required for safe operation, testing equipment design and its layout, crew competencies and SIMPOS protocol was prepared. The HSE requirements checklists were developed, reviewed and agreed based on the scope of work both for the drilling and testing phases in a highly congested brown field. The aim was to complete entire operation expanding over 2-3 years without jeopardizing the nearby activities and production. Due to the critically and strategically importance of the project, all the available best practices and technical competencies were applied in this project which allowed to overcome all the SAFETY challenges during drilling, tie-in and testing of these crucial wells. All objectives were successfully achieved with no HSE incidents and failures. Findings and lessons learned are being used to tailor next stage of the project to ensure most efficient scenario of Field development to support country’s increasing gas demand. All existing HSE assurance measures, procedures and programs were reviewed and implemented to suit the condition of sour wells including:Fire & Gas detection, Emergency Shutdown Systems and their layoutsEnvironmental Impact Studies focusing on the potential effects of flaring from sour wells including Zero spill and safe disposal of produced fluids into dedicated disposal wells drilledEstablishing and aligning all communications for imposition of EPZ (emergency planning Zone) and Site Specific Safety Plan with emergency response/evacuation procedures including SIMPOS with multiple evacuation route maps preparedEmergency communication protocol was developed considering the nearby population/towns in case of any gas release.Civil defense, Police and other governmental agencies were informed and ensured their participation during the large scale exercises carried out This paper provides an insight of steps taken to achieve the target of drilling/testing highly sour gas wells safely in brown field. Successful implementation and close follow up of all measures/controls identified in SIMOPS thru multiple audits; resulted in drilling, tie-in and testing of Sour gas wells with no safety incidents or injuries. All routine rig and rigless activities in the vicinity were performed safely complying fully with SIMOPS and no operation was stopped. This paper emphasis importance of following all rules and regulation set by HSE to achieve the objective safety and efficiently. A typical brown field having operational challenges while drilling and testing highly sour gas well

ADNOC onshore tested HPHT sour gas reservoirs with 30% H2S, 10% CO2 to evaluate the reservoir and well potential as part of the efforts in supplying additional gas for meeting country's growing energy needs. Developing these massive HPHT sour gas reservoirs is essential for providing a sustainable source of energy for years to come. This critical project serves the broader national strategy and country aspirations in fulfilling the gas demand over the next few decades to come. Few HPHT sour wells were drilled but only one well could be tested successfully. The other two wells had to be suspended due to HSE /environmental and operational reason as elemental Sulphur was detected. Based on the previous well test and reservoir data, it was decided to use one of the existing well and sidetrack in the Sour reservoir to gain experience about drilling a long horizontal section in the High pressure, high temperature sour condition. A specialized drilling Rig capable of drilling the long horizontal well was selected. Due to nature of the reservoir, specialized sour service drilling tools were selected considered the long departure and long open hole horizontal length of 10000+ ft. Selection of the downhole material for these conditions was itself a challenge as very few vendors or IOC (Internatioanl oil companies) have experience of developing and producing from +30% H2S and +10% CO2. Due to the location of the well, stringent HSE measurements were adapter to ensure zero tolerance for the safety violation in accordance with 100% HSE. The testing of the HPHT sour gas was challenging due to not only HSE issues but also from the environment part too as flaring needed to be minimized in the brown field. Hence, it was decided to Tie-in the well to the nearby facilities. The challenge was that the existing facilities were not design to accept the sour gas. This was overcome by blending the sour gas with sweet gas to meet the existing facilities specs and capacities. After the well was drilled, the +10000 ft. open hole was flowed to clean to ensure all the drilling fluid lost was recovered to test to access well potential and obtain representative data for full field development plan. Drilling, testing and producing the highly sour HPHT gas reservoirs with more than 30% H2S and 10% CO2 along with temperature ranging up to 300 deg F is itself a huge challenge. Over the last few years, ADNOC Onshore have developed considerable expertise in testing the sour wells considering all the safety and environmental aspects. This paper highlights the work progress and the lessons learned during each step of the operation from planning phase to drilling, tie-in the well to the existing facilities after dilution during testing. All the proposed mitigation plans considering 100% HSE while dealing with these appraisal wells in the Arab sour reservoir having +30% H2S and 10 % CO2 were developed and implemented sucessfully.