This paper describes an integrated approach for key well evaluation using open hole well logging technology and core analysis. The information set includes nuclear magnetic resonance (NMR), wellbore electrical image, wireline formation tester, dipole sonic, conventional nuclear and resistivity logs and core data from a carbonate field. The objective was to characterize formation static and dynamic properties prior to water injection. The integrated analysis gave a good overall picture of the formation, including permeability anisotropy. Several sources of information were compared and their results were discussed. Permeability values obtained from the analysis of wireline vertical interference tests were input into the full field simulation model. Introduction An integrated data gathering and analysis approach was selected for a key well study drilled in an onshore carbonate oil field. Conventional open hole logs were used for porosity and saturation analysis while formation electrical images were used to investigate fine layering, different porosity types and fracture development within the study interval. NMR is now routinely used in sandstone formations to provide a continuous permeability log close to the borehole wall, but has not proven to be reliable in many carbonate formations. The major obstacle for using NMR to evaluate permeability in carbonates has been attributed to weak surface relaxivity, which compromises the relation between T2 and pore size distributions.1,2.Stoneley mobility indicator from dipole sonic is often used as a qualitative indicator of permeability but is difficult to scale as a quantitative measurement. Stoneley mobility indicator and wireline tester pretest mobility can compliment the NMR interpretation and improve its accuracy to provide a better continuous permeability log. The wireline formation tester was also used to conduct local vertical interference tests across tight zones to obtain in-situ vertical and horizontal permeabilities. These tests are relatively long and investigate a much larger volume of rock when compared with other open hole logs. The tests were conducted by producing from a wellbore section isolated between two inflatable packers and observing the resulting pressure response with a probe set above the tight zone. The acquired flow and pressure data was analyzed using a layered model for individual layer horizontal and vertical permeabilities. The results from this analysis were compared to core and NMR permeability data.

Monitoring and handling Sustainable Annulus Pressure (SAP) is a daily challenge in today's oil and gas industry. Well integrity failure can affect production and the environment and, consequently, lead to high economic losses from fixing the resulting damage. Once SAP is confirmed, its source should be located and shut off as soon as possible. The biggest problem is leaks behind multiple barriers, which are not clearly seen in conventional temperature and noise logs.[1] However, recent developments in temperature and noise logging tools and interpretive techniques have been rewarded by achieving high resolution and sensitivity enabling the detection of previously undetectable leaks.[2] This paper describes two cases of integrity failure in the B and C annuli detected by the new integrated high-precision temperature and spectral noise logging technique, or HPT-SNL.

Placing a horizontal well successfully within the target reservoir layers of uneven surfaces with uncertainties in dip and thickness is not a simple task, particularly in areas structurally disturbed. The level of difficulty increase when the well intersects a sub-seismic fault of unknown attributes. In such cases it becomes very difficult to decide which way to steer the well, so that it could re-enter the zone of interest, or which part of the reservoir is drilled after intersecting the fault. A limitation to geological steering is the relatively small volume of investigation of the traditional logging while-drilling (LWD) sensors, which can typically probe no farther than few inches into the formation. A new LWD directional, deep electromagnetic propagation service was recently developed with a much larger radial response that delivers distance and direction to the nearest change in resistivity within a formation, in addition to the resistivity of each of the formation layers. A case study is presented onshore Abu Dhabi field of the United Arab Emirates, where information from the deep directional propagation LWD tool, together with near-the-bit direction and inclination measurements enabled to take proactive and timely corrective drilling actions to optimize the placement of the well path. A team from Petroleum Development and Drilling was formed with specific objectives to maximize reservoir exposure and minimize drilling risk and to insure 24 hours communication and real time data transmission between service and operating companies. The result was a well with 100% of its length in the desired reservoir. It was possible to achieve the field production target for this gas reservoir, drilling only 5 of the 7 wells originally planned.

The traditional way of acquiring reservoir fluid samples (prior to production) has usually involved running a wireline formation tester for several days or even weeks after drilling the well. This time delay between drilling and sampling has an adverse effect on obtaining high quality fluid samples because of long-term exposure to invasion. This effect becomes worse in low permeability formations where effective mud-cake build-up is poor, resulting in deeply invaded formations. In turn, this requires large volumes of filtrate to be pumped back out of the formation in order to collect low contamination reservoir fluid samples. The ability to sample while drilling using LWD technology solves part of this problem by allowing the pump-out to start much earlier in the invasion process, thereby reducing the volume of filtrate required to pump out of the formation. In addition to cost-savings from reduced sampling time, there are other benefits to LWD sampling such as continuous circulation. This can be critical when multiple reservoirs are exposed, some of which may be depleted and pose differential sticking risks, which is often the case in the Middle East. However, current LWD sampling technology is done with a probe which limits the inflow area thereby complicating the sampling process in low permeability formations. Many of the giant carbonate reservoirs in the Middle East are highly heterogeneous and have low average permeabilities (<1-5mD) making it difficult to sample with a standard probe in many situations (LWD technology cannot overcome all the challenges just yet). But viscosity is also critical and the overall mobility of gas reservoirs can be relatively high due to the low gas viscosity, thereby making gas samples a potential application for this new LWD technology in Middle East carbonate reservoirs. Formation pressures and fluid samples were taken from such a reservoir. In this field there is known condensate banking and the project involves re-injecting the produced dry gas into the reservoir to help maximize the condensate recovery. Seven (7) samples were collected using an LWD sampling tool, and subsequent lab analysis on the samples confirmed condensate in the reservoir. This new technology is seen as a way to help maximize recovery and minimize costs.

Geomechanical modeling is important to understand in-situ stresses, reservoir stress path, stress contrast, wellbore stability, solid production, integrity of cap-rock and drilling vertical and horizontal wells. The knowledge of the in-situ stresses is critical for pre-drill and post-drill well planning as well as wellbore stability prediction and is needed throughout the life of a well. The uncertainty associated with this geomechanical modeling can be critical and costly if these uncertainties are not mitigated and, to reduce this uncertainty, it is important to have a calibrated geomechanical model. One important technology that can help with reducing the uncertainty is the wireline straddle-packer microfrac tests for in-situ stress characterization. It is an important technology that helps in the measurement of in-situ formation breakdown pressure, fracture propagation pressure and fracture closure pressure. It also helps with other important hydraulic fracturing design such as fracture containment assessment, horizontal stress profile and stress contrast to stimulate tight formation shale gas or oil, water disposal wells and for OBM cutting reinjection wells. The microfrac testing procedure uses the pressure response measured during formation breakdown, fracture propagation, fracture reopening cycles and pressure fall-off cycles for overall stress measurement and fracture closure identification. The objective of this microfrac testing was to validate and calibrate the horizontal stress profile in various intervals of the target formations. This paper focuses on the microfrac testing methodology, the geomechanical principles governing the testing, the resulting interpretation and the geomechanical modeling for horizontal stress calibration in a vertical borehole onshore Abu Dhabi.