TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCompartmentalization is perhaps the single biggest risk factor in deepwater petroleum production. Downhole fluid analysis (DFA) is a new tool to reduce uncertainty associated with reservoir connectivity. Fluid data from DFA logs and various laboratory analyses are studied to elucidate hydrocarbon composition variations in large reservoir sand bodies. This procedure was applied in the Deepwater Tahiti field in the Gulf of Mexico uncovering a large concentration variation of asphaltenes. These asphaltene nanoparticles are shown to be colloidally suspended in the crude oil in agreement with recent laboratory results, and settle preferentially lower in the oil column in accord with the Boltzmann distribution. Relevant fluid features, in this case the asphaltene concentration gradient, are then integrated in a geologic model and used to predict crude oil properties and DFA logs for all hydraulically connected sections of the reservoir. Predicted and newly acquired DFA log data matched for the first production well, establishing that the penetrated sands are likely connected, mitigating compartmentalization risk.This DFA log prediction protocol offers a new method to optimize wireline logging.

In order to design oil production facilities and strategies, it is necessary to acquire crude oil samples from subsurface formations in oil wells in so-called openhole prior to production. In some environments, such as deepwater production of oil, decisions of huge economic importance are based on such samples. To date, there has been little quality control to verify that the crude oils collected in the sample bottles and analyzed up to a year later in the laboratory have any relation to the actual crude oils in the subsurface reservoirs. These high-pressure samples can undergo myriad deleterious alterations. Here, we introduce the chain-of-custody concept to the oilfield. The visible-near-infrared spectrum of the crude oil is measured in situ in the wellbore at the point of sample acquisition. This spectrum is compared with the spectrum measured on putatively the same fluid in the laboratory at the start of laboratory sample analysis. First, quantitative assessment is made of whether the fluid in the (high-pressure) sample bottle remains representative of formation fluids. Second, any specific changes in the spectrum of the fluid can be related to possible process control failures. Here, the entire process of chain of custody is proven. The chain of custody process can rapidly become routine in the petroleum industry, thereby significantly improving the reliability of any process that depends on fluid property determination.

This paper describes a new technique for measuring pH on live formation water samples in the laboratory at high temperature and pressure. The technique involves adding pH sensitive dyes to pressurized single phase water samples collected using a formation tester and spectroscopically determining the pH in the laboratory at reservoir conditions. Water chemistry and pH are important inputs for scale and corrosion modeling. Due to the lack of standard laboratory techniques for such measurements at high temperatures and pressures, current practice involves flashing the single phase water sample, analyzing the flashed water and gas phases, and then using water chemistry models to predict pH at reservoir conditions. Uncertainties in the thermodynamic models for formation waters at high temperature and pressure, as well as uncertainties associated with the flash process and possible precipitation of salts, can propagate as errors into scale and corrosion models. It is proposed that the direct pH measurement on live water samples described here be used as an additional input for the water chemistry models to improve confidence in their predictions. This will allow for more efficient selection of completion materials and planning for scale treatment and mitigation. In this paper, we present results of laboratory pH measurements on formation water samples from two offshore Gulf of Mexico wells for pressures to 20,000 psi and temperatures to 242°F. Results are compared to predictions from two commercial thermodynamic models that use the flashed gas and water analysis data as inputs. The setup can also measure the sensitivity of pH to pressure and temperature. Comparison of the laboratory pH measurement to real-time in situ downhole pH measurements made on the same formation water with a formation tester showed good agreement. This is an example of the implementation of the chain of custody concept, which compares a measurement made downhole with that made in the laboratory on the same sample using the same technique, to validate the representativeness of the sample as it is transported from downhole to the laboratory. Introduction Water sampling in exploration wells is usually done to obtain information regarding the scaling and corrosion potential of the water, understand reservoir connectivity, and establish the salinity of the water for petrophysical evaluation. Corrosion potential of the water is important for material selection for tubing, pipeline, and process equipment. Scaling potential is critical for the selection of an optimal development strategy to prevent scale formation by choice of operating conditions, to select and deploy scale inhibitors when needed, or both. Correct water resistivity is important for interpreting openhole wireline logs accurately. In addition, analysis related to various environmental aspects like concentration of organic compounds and heavy metals in water is performed. Dissolved organic acids also affect water chemistry because they can influence the pH of the solution. Good quality formation-water data can improve the ability to make the right decisions early in development planning. These data can give information about compartments and communication in the reservoir. Later in the production cycle, these data can be used to differentiate produced connate water from aquifer or injection water breakthrough.

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