TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAs production logging technology advances, more confident results are achieved in multiphase horizontal wells. There are a number of wells with unfavorable completions for production logging. In addition, operational difficulties are observed from time to time posing challenges. In any case, confidence in the determination of fluid entry intervals is required. Because of dynamic data acquisition, real time decisions are needed.

Calcium carbonate scale represents a significant safety and operational problem in offshore carbonate fields operated by Saudi Aramco. Scale can form on any surface where the pressure drop is sufficient for the produced fluids to form the scale and unload entrained solids. These solids will deposit on wellhead equipment such as the wellhead surface valves, piping, well tubulars and may plug the perforations. Well safety is jeopardized by hindering the operation of critical safety valves such as subsurface safety valves (SSSVs) and surface safety valves (SSVs). Further, scale buildup can cause backpressure problems in the tubing as the pipe internal diameter is reduced. Identification of scale in impacted wells requires periodic inspection and repair. This paper presents Saudi Aramco's experience in eliminating calcium carbonate scale by treating existing scale using HCl acid. Scale mitigation was initially attempted using an encapsulated inhibitor placed in the rat hole of vertical wells. This method had a limited treatment effective life and Saudi Aramco has moved to using inhibitor squeeze treatments. Chemical squeezes places inhibitor (phosphonate-based) directly into the formation of wet oil producers and is now the currently employed method of long-term prevention of scale. Case studies using both methods of scale mitigation are discussed as well as future plans to improve the effectiveness of these treatments. Introduction Field "B" is located both onshore and offshore along the western edge of the Arabian Gulf. The field is a north to south trending, elongated, anticlinal structure which measures 40 Km in length and 19 Km in width. This field was discovered in June 1964 and oil production began in 1967. Field "B" is a multi-reservoir field with 11 oil-bearing reservoirs at various depths from 2,133 to 3,048 meters (7,000 to 10,000 ft). The crude grade is Arab Extra Light crude with 7.5 mol% H2S and 4.5 mol% CO2. The two main reservoirs in this field are the HN and HD. The main productive formations have a low permeability in the range of 1–50 mD. The HN and HD reservoirs are carbonates reservoirs. Bulk XRD analysis of the HN reservoir cores indicates that the zone of interest contains 97–100 wt% calcite and 0–3 wt% ankerite. On the other hand, HD reservoir cores contain 70–92 wt% calcite, 0–30 wt% dolomite and 0–5 wt% ankerite.1 For pressure support purposes, peripheral water injection began in 1973 using 14 injectors into the HN reservoir and 28 injectors into the HD reservoir. The injection water is drawn from a shallow aquifer. The produced water is injected into a separate, segregated disposal system. Water breakthrough first occurred in the HN reservoir in mid 1975 and in late 1978 in the HD reservoir. Water-handling facilities were placed in service in 1983. The water cut for both the HN and HD reservoirs has gradually increased since the commissioning of these facilities and currently the field produces crude oil with an average water-cut of 32 vol%. The first scale build-up problem was encountered in 1987. Since then, scale became a difficult problem to manage as more wells started to produce formation or injection water. Scale build-up has resulted in several operational problems and production losses. The main objectives of this study are to:give a brief summary on the scale problems encountered in Field "B" carbonate reservoirs,discuss how this problem was addressed, andsummarize field experience gained from solving this problem. Chemical Analysis of the Formation Brines The composition of the produced water varies significantly for the HN and HD reservoirs as noted in Table 1. The Total Dissolved Solids (TDS) for the HN reservoir brines varies from 27,000 to 230,000 mg/L. The calcium ion concentration is in the range of 1,904–18,876 mg/L. The TDS for the HD reservoir brines is higher than that of the HN brines and varies from 33,400 to 292,000 mg/L. Calcium ion concentration is in the range of 2,392 to 39,280 mg/L.

Wireline formation testing provides formation pressures, high quality samples and fluid identification/characterization. In addition, it can provide information for reserve assessment and producibility estimation. In this paper, we present comprehensive formation evaluation case histories with formation testing utilizing a focused sampling probe in wells drilled with Oil Base Muds (OBM) in mature fields. Due to OBM and low mobility sections, a new focused sampling device was utilized for effective formation testing and sampling purity. One case history demonstrates confirming remaining oil saturation. Conventional open hole and Nuclear Magnetic Resonance (NMR) logs were run for formation evaluation, and fluid saturations. Gas and remaining oil saturation were obtained from 3D NMR analysis. Sampling lab results and real time analysis of gas compositions are also compared for verification and confidence. Two field examples in low porosity/low mobility zones are presented showing the identification of mobile fluids. It is shown that the existence of mobile oil could have been missed without effective formation testing practices. The third field example of formation testing with low porosity as well as low resistivity is provided for the identification of mobile oil. Flow was enabled from low mobility zones along with low rate pumpout that would not be possible with traditional probe and pumpout devices. The final field example of water sweep evaluation in high permeabilitiy/mobility zones demonstrates using formation testing as a means of reservoir monitoring. Introduction Recent advances in wireline formation testers enabled the determination of several fluid properties, including fluid compositions in real time. The applications of wireline formation testing has been discussed in a number of publications concerning Downhole Fluid Analysis (DFA)1–4. It has been shown that compartmentalization and compositional variation can be positively identified. This evaluation can have significant impact on facility sizing and economics of field development of new reservoirs. In addition, mini-DST or Interval Pressure Transient Testing (IPTT) can be carried out at DFA stations to provide more representative and accurate mobility/permeability distributions of reservoir layers5 for reservoir characterization. Mature reservoirs can have different objectives and challenges for efficient formation evaluation and reservoir management. As gas cap expands and active aquifer water moves in heteregenous systems, formation pressure profiles can be more complicated. Evaluation of saturations/remaining oil determinations becomes quite important for the determination of sweep efficiency in mature reservoirs. Low porosity/low permeability sections can be more challenging to evaluate and these sections can still have considerable hydrocarbon potential. Although, OBM can be challenging for contamination quantification during sampling operation, it has been shown that optical spectroscopy can be quite effective to overcome contamination challenges6. The challenge can be much more in the case of determining small amounts of mobile oil in a gas expanded zone, drilled with OBM. A focused sampling device is introduced to overcome this challenge by isolating small amount of filtrate that can mix with sampling line. Lab results of the first field example demonstrated that these objectives were achieved.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWireline formation testing provides formation pressures, high quality samples and fluid identification/characterization. In addition, it can provide information for reserve assessment and producibility estimation.In this paper, we present comprehensive formation evaluation case histories with formation testing utilizing a focused sampling probe in wells drilled with Oil Base Muds (OBM) in mature fields. Due to OBM and low mobility sections, a new focused sampling device was utilized for effective formation testing and sampling purity. One case history demonstrates confirming remaining oil saturation. Conventional open hole and Nuclear Magnetic Resonance (NMR) logs were run for formation evaluation, and fluid saturations. Gas and remaining oil saturation were obtained from 3D NMR analysis. Sampling lab results and real time analysis of gas compositions are also compared for verification and confidence.Two field examples in low porosity/low mobility zones are presented showing the identification of mobile fluids. It is shown that the existence of mobile oil could have been missed without effective formation testing practices.The third field example of formation testing with low porosity as well as low resistivity is provided for the identification of mobile oil. Flow was enabled from low mobility zones along with low rate pumpout that would not be possible with traditional probe and pumpout devices.The final field example of water sweep evaluation in high permeabilitiy/mobility zones demonstrates using formation testing as a means of reservoir monitoring.