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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPrecipitation from and corrosion by formation water coproduced with target hydrocarbons can cause serious problems, and an early knowledge of water chemistry is important for completion and facilities design. Owing to the high cost of interventions, this knowledge is particularly important in deepwater developments and subsea completions.Samples of formation water are obtained by producing from the well completed in the water leg or sampling after water production occurs naturally. The former method carries significant cost and the latter method may delay the knowledge of the water chemistry.Alternatively, a formation tester can be run into the wellbore to collect small samples directly from the formation.. In wells drilled with water-based mud, the results are generally mixed because successful collection of formation water requires that the tool be able to discriminate between the water and invaded filtrate. The method depends on the contrast in color or resistivity between formation water and water-based mud filtrate to determine when it is collecting water, and this contrast often doesn't exist.This paper presents a new solution. A mud tracer was used to change the optical properties of the mud filtrate to make it detectable downhole. Laboratory experiments checked the compatibility of the tracer with gypsum or glycol mud system, sensitivity to high clay content, and ability to be detected with another tracer, and individually and in combination with a dark-colored filtrate. Shop experiments were carried out to establish a relationship between different tracer concentrations and optical properties at specific wavelengths. This relationship represents the basis of tracer detection and contamination prediction in real time downhole.The first trial was carried in the Otter field in the northern North Sea. The field comprises three producers and two injectors with subsea completions. Downhole water samples were obtained during the logging phase on one of the injectors at an early stage of the field development. Sample quality and flushing time were optimized using the new technique. Sample analysis results compared well with later production tests.

Precipitation from and corrosion by formation water co-produced with target hydrocarbons can cause serious problems, and an early knowledge of water chemistry is important for completion and facilities design. Owing to the high cost of interventions, this knowledge is particularly important in deepwater developments and subsea completions. Samples of formation water are obtained by producing from the well completed in the water leg or sampling after water production occurs naturally. The former method carries significant cost and the latter method may delay the knowledge of the water chemistry. Alternatively, a formation tester can be run into the wellbore to collect small samples directly from the formation.. In wells drilled with water-based mud, the results are generally mixed because successful collection of formation water requires that the tool be able to discriminate between the water and invaded filtrate. The method depends on the contrast in color or resistivity between formation water and water-based mud filtrate to determine when it is collecting water, and this contrast often doesn't exist. This paper presents a new solution. A mud tracer was used to change the optical properties of the mud filtrate to make it detectable downhole. Laboratory experiments checked the compatibility of the tracer with gypsum or glycol mud system, sensitivity to high clay content, and ability to be detected with another tracer, and individually and in combination with a dark-colored filtrate. Shop experiments were carried out to establish a relationship between different tracer concentrations and optical properties at specific wavelengths. This relationship represents the basis of tracer detection and contamination prediction in real time downhole. The first trial was carried in the Otter field in the northern North Sea. The field comprises three producers and two injectors with subsea completions. Downhole water samples were obtained during the logging phase on one of the injectors at an early stage of the field development. Sample quality and flushing time were optimized using the new technique. Sample analysis results compared well with later production tests. Introduction Water production happens naturally in many oilfields. Generally, the production of water is unwanted and measures are taken to avoid or to minimize it. Knowledge of the chemistry of the produced water is incorporated into the production process. For example, potential for scaling and corrosion influences material selection of the well completions and surface facilities. The quality of produced water may also impact the decision about water injection for the fear of mixing incompatible waters.1 It is expensive to dedicate a production test for the sole purpose of obtaining a formation water sample. Although information about water chemistry is important, the cost of obtaining a sample can be high enough that the test may be delayed or canceled if obstacles arise. Wells generally are completed with the aim of preventing or at least delaying water production, so it sometimes seems easy to defer analysis. Water chemistry may thus be only available when water production naturally occurs, long after metal completion goods, chemical injectors, etc. have been placed. This may not be the ideal situation. Therefore, obtaining a formation water sample using a wireline formation tester at an early stage of field development is an attractive solution. If the sampled well is drilled with oil-based mud (OBM), current technology provides a simple way to differentiate between OBM filtrate and formation water2,3. If the sampled well is drilled with water-based mud (WBM), differentiation can be difficult. The most commonly used downhole sensors rely on resistivity or the colour difference between formation water and WBM filtrate. Often these values are close and can not be used as a mean of differentiating the two fluids. As we report, adding the proper synthetic dye to the WBM colors the filtrate, providing clear differentiation from formation water.

Carbonates are infamous for their complex intrinsic heterogeneity, exaggerated due to stratification and layered geology. Characterization and correlation of this heterogeneity with recovery mechanisms becomes critical pertaining to Lower Cretaceous reservoir ‘A’ with over 4 decades of production/injection history. Hence, it is pertinent to systematically reduce the uncertainties associated with reservoir characterization by delineating high permeability streaks, permeability-contrasts, links between geological and petrophysical facies and their impact on field scale production/injection strategies. Emphasis was put on capturing downhole dynamic Kv/Kh profile across sub layers of the reservoir ‘A’, to enable assignment of representative values into reservoir simulation model with associated reservoir zonation. Vertical interference testing (VIT) was designed in a crestal location well with a history of near-by waterflooding, integrating simulator-based outputs with petrophysical and borehole image logs of an offset. Drawdown-buildup cycle was performed across source probe or packer, while simultaneous monitoring of pressure at observation probe. To reduce uncertainty and incorporate statistical sense into the data, multiple cycles of drawdown-buildup were conducted for vertical connectivity evaluation. In total, eleven VIT tests conducted with formation tester tool utilizing dual-straddle-packer and two-probe modules were interpreted implementing a systematic approach considering vertical communication as a function of geological facies and textural aspects from borehole images, geological information on fractures/faults, and surfaces. Interpretation involves identification of flow-units based on available logs, followed by identification of flow regimes (spherical/radial) to history-match data for estimation of horizontal and vertical permeabilities of each layer. Resultant analysis yielded insights on anisotropy by validating vertical communication through stylolite and across dense layers. Integration of VIT analysis results (Kh,Kv,Kv/Kh) with petrophysical logs led to the establishment of water flood advancement mechanism in this observation well at the crestal location of field. This establishes a critical link between integrated geological, textural and facies analysis in context of sedimentology, layering and rock quantified fabric permeability indicators visible on high vertical and horizontal resolution borehole image. Thereby, allowing derivation of scalable answer products and workflows. Subsequently, explaining water flood mechanism and enabling updating of simulation model for enhanced reservoir characterization. Furthermore, this also allows for field development augmentation and injection strategy optimization through linking of dynamic results to reservoir description of two major sub-layers of this giant carbonate field. Integration and analysis of key insights on vertical communication and carbonate anisotropy with major geological/petrophysical features aided in characterizing 3D static and dynamic models. This would allow improved trajectory planning of future wells, leading to improvement in recovery efficiency through guided injection strategy. Additionally, proactive data aggregation and insightful interpretation to help accelerate realization of value from field development strategy was highlighted.

Formation testers are being widely used worldwide in open hole, especially in exploratory wells where fluid identification, downhole sampling, determining pressure and mobilities are very critical. Sometimes, due to tight formations, unconsolidated sands or excessive borehole washouts/breakouts, it is not advisable to pump, because with longer stationary times there is high risk of differential sticking. In this scenario, cased-hole formation tester comes into play. The whole operation involves perforating 1 foot interval in casing, then isolating the perforated interval with straddle packers (3.28 ft or 1m apart). This is followed by pumping to establish fluid type and representative sampling. Later, extended buildup is acquired for reservoir characterization until transient reaches the radial flow regime (Mini-DST). Well A is located in XYZ Block, Pakistan and is operated by Pakistan Petroleum Limited (PPL).Pressures and mobilities were obtained with wireline formation testing probe module across open-hole which found the formation to be ultra-tight. Pumpout could not be acquired with probe module due to formation tightness, therefore the question of fluid type was unanswered. Additionally, across the prospective zone washouts were observed. Due to these factors, the well was cased to establish fluid type and reservoir characterization (permeability, skin and pressure) through cased-hole dual packer formation tester. After 10 hours of pumping, first gas breakthrough was observed on downhole fluid analyzer. Pumping was carried out for almost 22 hours in order to get representative samples. This was the longest pumping time ever on any well in Pakistan. Later, buildup was acquired since hydrocarbon presence was established (Mini-DST). Cased-hole formation testing is very helpful when dealing with layered reservoirs as testing of each individual layer on a full-fledge DST operation would be very costly, especially if the layers end up being declared as water bearing. Similarly, conventional DST operation for ultra-tight formations can cost a lot of rig days, whereas mini-drillstem testing can conclude the same with reasonable amount of rig time. The most important benefit of cased-hole formation testing is its capability to pump for longer durations with no risk of differential sticking, thereby expanding the possibilities for formation testing and sampling.