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Abu Dhabi Company for Onshore Oil Operations (ADCO) had a need for an exploration survey to delineate a low relief structure in onshore Abu Dhabi. The terrain is characterized by sand dunes of variable heights with some oilfield infrastructure, farms and conservation areas. ADCO tendered for a conventional survey but the successful bidder offered an economically attractive Single Sensor / Single Source (S4) option with the MD low frequency enhanced sweep. ADCO has tested some of the processing technology associated with S4 recording on vintage datasets and were keen to try them on a true S4 dataset. In particular it was very important that a good near surface model was obtained because of the low relief target. The use of the low frequency MD sweep, Shear Wave Inversion (SWI) and Simultaneous Joint Inversion (SJI) was an ideal approach to resolving the near surface model. There was an uphole program planned to calibrate the derived near surface model. The SWI volume was generated before the upholes were drilled so that any anomalies could be investigated. The crew with 50,000 channels mobilized and commenced operations on October 26th 2013 and completed the 604 Sq.km survey by December 25th. The survey consisted of 241,860 VP's and generated 3.5 billion traces. Despite this volume of data a field QC volume was generated on the crew utilizing a pre-defined velocity field developed in collaboration with ADCO and was delivered two days after the last shot. This volume was interpretable to guide the main processing team. Whilst the full processing and evaluation of the data is still ongoing, the early results have clearly shown that the S4 technique is ideally suited to acquisition in sand dune areas with infrastructure. This presentation outlines the details of this survey and the lessons learned.

Reservoir screening studies were carried out on all of ADCO’s reservoirs to determine their applicability for Underbalanced Drilling (UBD). These studies resulted in a prioritization of potential UBD candidates. The primary business benefits of UBD were determined as follows: –reduction of formation damage ○Productivity Improvement Factors (PIFs) much greater than 1 were determined in many cases;○potential elimination of complicated (and expensive) stimulation jobs.–dynamic reservoir characterization ○improved understanding of geological architecture/flow units and hence the potential for more accurate and reliable reservoir models;○improved completion designs. Some of the secondary benefits of UBD that were identified beforehand included Rate of Penetration (ROP) improvements while drilling and improved rig performance. In one field, it was demonstrated that the PIFs per well resulting from UBD would enable fewer wells to be used to develop the field by optimization of the horizontal well length and hence a significant reduction in capital expenditure. From these studies, two fields were selected to carry out initial trials. This paper describes the lessons learnt from the planning, design and subsequent implementation of UBD in the first well in ADCO, which involved a truly integrated and multi-disciplined team effort. An initial assessment of the business benefits obtained from the trial compared to the results of the initial screening studies is also provided.

Abstract Production rates from tight reservoirs are marginal. However, the tight carbonate reservoir under study accounts for a significant percentage of STOIP, which is the key for drilling and producing these reservoirs. The challenges here are to optimize both the production rates and the total amount of the recovered oil. Good understanding and high quality reservoir characterization lead to efficient reservoir management plans. The studied reservoir is over 50 ft thick and covers an area of 140 km2 with porosity ranges from 3 to 25 pu. This reservoir was deposited during a transgressive cycle on a broad and relatively shallow shelf in an open to slightly restricted subtidal marine environment. The depositional environment plays the major role as well as the diagenitic overprint in term of low reservoir quality. The reservoir is subdivided into four sub zones separated by stylolites. The reservoir can be divided into two main facies fining upward. Although the lower facies composed of Algal Skeletal Floatstone-Boundstone while the upper one is Foraminifera Wackestone, the reservoir quality is relatively low in both (permeability does not exceed 6 mD) due to the severe impact of digenesis. Although a production test conducted over this reservoir reached only 300bopd dry oil, it is still encouraging to implement a sound development plan in order to sustain a reasonable plateau and obtain an optimum recovery. Moreover, the reservoir structure is quite complex in term of isolation with the overburden dense formation and juxtaposition with lower reservoirs. Several options are considered to develop this tight reservoir, but basically they consider the use of long horizontals under WAG and Gas injection processes. Introduction As the industry seeks to increasingly exploit reserves of oil contained in low permeability reservoirs, the reservoir under study present an average permeability of 1 mD. Many questions have been raised about how to optimize production rate, the total amount of the recovered oil and the optimum practice to drill and complete this kind of reservoir. The effective stimulation technique to obtain economic production rate is another issue. The reservoir damages during the drilling operations and workover also represent a concern. Geological background The structure of the reservoir is characterized by a highly faulted elongated NE-SW anticline with a main axis length around 25km and a width of approximately 6km covering an area of 140km2. fig.1 The structure was formed during the Upper Cretaceous in response to the compressional event related to the main ophiolites obduction. Subsequent movement of the structure during the Tertiary has occurred due to the Zagros orogene event which has regionally tilted the area down the NNE.

Two 126 level 3-component 3D-VSP's (Vertical Seismic Profiles) were acquired coincident with a high-resolution surface seismic survey. Figure 1 shows the location of the first 3D-VSP on the crest of the field and the second 3D-VSP on the flank of the field. Using the surface seismic sources, 11712 shot points were used per VSP to collect 4.5 million traces per VSP, which produced a 6-9 km² final 3D-VSP image around each of the two wells. Due to the large offsets and high density of traces available it was possible to experiment with acquisition and processing methodologies to produce images that resolve thinner beds, see more structural definition and improve reservoir characterization. Results from the first phase of processing are very encouraging and show the 3D-VSP images to be able to resolve subtle faults that were not seen in older surface seismic data and have higher frequency content than the new 640 fold, high resolution surface seismic data. Source and receiver decimation tests are aiding in efforts to better understand how to acquire high quality 3D-VSP's in the future with minimal effort and cost. Efforts to expand the size of the 3D-VSP volumes around the wells have been successful. The largest image produced so far has been able to image more than 1.5 km away from the wellbore. The high quality VSP images and the fact that VSP's can be repeated at much lower cost than surface seismic makes this technology very attractive for future time-lapse reservoir monitoring studies.