Abu Dhabi National Oil Company (ADNOC) and its group of companies completed a review of logging practices in Feb. 2000.1 A recommendation was made to compare PNC tools in a properly characterized well under controlled conditions. This report addresses that recommendation by comparing the accuracy, repeatability and reproducibility of two new and two older generation PNC tools currently available for field monitoring in Abu Dhabi reservoirs. Tools are compared against each other and to core measurements. Elemental analysis of core and reservoir condition fluids provided the benchmark for formation capture cross-section comparisons. One tool displayed much poorer statistics than the other tools. All tools suffered from large inaccuracies in their auxiliary porosity measurements. Reproducibility was good for sigma measurements but poor for porosity. Three of the four tools are acceptable for qualitative field monitoring operations. Two of the tools are preferred for accurate residual oil measurement. Introduction ADMA-OPCO employs Pulsed Neutron Capture (PNC) tools run repeatedly over time in selected cased boreholes to monitor the rate of peripheral waterflood advance. Time lapse PNC monitoring requires precise but not necessarily accurate tools.2 The main requirement is reproducibility of the measurement, tool to tool, for the same tool design. In addition to qualitative water flood monitoring, quantitative gas flood monitoring studies are in progress or planned in two reservoirs. PNC tool accuracy, repeatability and reproducibility are important attributes to the performance evaluation of these projects. Occasionally PNC tools are used for determination of remaining oil saturation, as a check on resistivity based log interpretation, and to measure water saturation when no open hole logs are gathered. Accurate sigma formation intrinsic (SFMINT) and porosity are required. Measuring an accurate SFMINT is difficult, the borehole environment (fluid, casing, cement), perturbs the formation decay signal by adding unwanted components collectively known as borehole signal. Diffusion, the tendency of neutrons to migrate from high population regions to low population regions is a complicating factor. It presents an apparent change in sigma formation not due to neutron die away. Developers of each succeeding generation of PNC tools have sought to move the oil industry closer towards the goal of measuring accurate intrinsic sigma formation.3,4 Four different 1 11/16" diameter PNC tools are available from the service companies in Abu Dhabi. Two of the tools are the latest generation capable of measuring both sigma formation and carbon oxygen ratio. For the purposes of this paper the two earlier generation tools are called ‘A1’ and ‘B1’ and the latest generation tools are referred to as ‘A2’ and ‘B2’. The last published examination of PNC tool SFMINT accuracy was by Bonnie in 1991.5 He concluded it was still not possible to measure sigma formation intrinsic under all logging conditions. Bonnie did not reveal which of the tools tested (TDT-M, TDT-P, PDK-100, TMD, & TDS) provided the best accuracy under the conditions tested, nor comment on the repeatability of the various tools. Salaita6 in 1992 investigated PNC sigma repeatability during an extensive comparative field test of the TDT-K, TDT-M, TDT-P and PDK 100. Newer generation tools exhibited better precision than older designs. Neither Bonnie5 nor Salaita6 examined reproducibility of the tools, arguably the most important attribute for reservoir surveillance. February 2000, Abu Dhabi National Oil Company (ADNOC) and its group of companies completed a review of logging practices.1 A recommendation to compare PNC tools in a properly characterized well under the controlled conditions was made. ADMA-OPCO, one of the review participants, was in the process of drilling an observation well for a gas injection pilot scheduled in two years time. This presented an opportunity to compare and evaluate the performance of PNC tools in a common environment. This paper reports the results of that comparison.
During the past four years Saudi Aramco has used short radius horizontal and multilateral drilling technology to increase oil recovery, productivity and injectivity of existing production and injection wells. This was achieved by(a) sidetracking oil wells with thin bypassed oil column and drilling shortradius horizontal holes at the top of the reservoir to control water coning and increase oil recovery, (b) drilling short radius horizontal holes across thin reservoirs and increase the wellbore flow area and well productivity, and (c)drilling multilateral short radius horizontal holes to increase the productivity and injectivity of existing oil and water injection wellscompleted in low permeability reservoirs. This paper presents well casehistories that describe the drilling and completion operations and compare the performances of the horizontal and conventional wells. Introduction The Arab-D is the major oil producing reservoir in the Ghawar field in SaudiAramco. The reservoir is dolomitic limestone and has a net thickness of about 250 ft. The formation porosity and permeability are highest at the top of the reservoir and decrease gradually to ± 5% and few millidarcies at the base of the reservoir. The Arab-C reservoir which lies above the Arab-D is, in someareas of the field, a water-bearing and highly pressurized reservoir. The two reservoirs are separated by 100–170 ft of anhydrite cap rock and the thin postArab-D stringer which is oil-bearing in some areas of the field as shown inFig. 1. Most wells in the field are initially completed open-hole in the Arab-Dwith the 7" liner set at the top of the reservoir. The post Arab-D stringer isnot produced in wells completed in the Arab-D reservoir. The Arab-D reservoir pressure is maintained by the injection of water on the flanks of the field. Aswater injection continues, the water cut increases until the wells can nolonger flow on their own, leaving 25–35 ft of unswept oil column at the top of the reservoir. One way to recover the unswept oil is to run and cement a 4-1/2" liner across the open hole and perforate across the unswept zone. The disadvantage of this method is the problem of water coning. As oil production from the unswept zone continues, the water cone rises around the wellbore and as a result the water production increases until the well dies before the oil in the unswept zone is recovered. Applications of Short Radius Horizontal Drilling : Short radius horizontal drilling technology was used to increase recovery of the unswept oil at the top of the Arab-D and to increase the potential of oil and water injection wells. Existing oil producers and water injection wells in the Ghawar field were reentered and short radius horizontal single and multilateral holes were drilled. This technique provided an attractive cost benefit compared to drilling new wells since the infrastructure is already inplace. Short radius horizontal completions were utilized in four major applications outlined below. Recover Unswept Oil from the Top of the Arab-D Reservoir. Many oil producers in the Ghawar field ceased to flow because of high water cuts leaving 25-35 ft of unswept oil at the top of the reservoir. Reentering the wells and drilling short radius horizontal holes across the top of the reservoir proved to be the most economical and effective way of recovering the unswept oil.
Identifying the location and quantification of flow units is critical to managing a reservoir's production and achieving maximum recovery. Gas injection is planned in a limestone reservoir offshore Abu Dhabi. To understand the benefits of future full field gas flooding, a pilot covering three reservoir units is underway. Ten wells were drilled and significant log/core data acquired. Interference tests within a reservoir unit in single wells and between-wells have revealed useful insights into the vertical and lateral continuity of barriers and conduits to flow. Recovery efficiency is driven by these contrasts in the reservoir sublayers. Significant variations in permeability occur over short vertical distances due to local facies and diagenetic changes, including dissolution events, distorting associations between porosity and permeability. Porosity cannot predict permeability to better than 1.5 decade on a logarithmic scale in this reservoir. Experimenting with NMR, Stoneley wave responses on one well, we were able to improve our predictive capabilities by combining the strengths of each tool. Predicted values fell mostly within half a log cycle of the whole core measurements. Vertical interference testing with a multi-probe Modular Dynamic Formation Tester (MDT?) used in a totally new way and using single well numerical models, proved useful in defining vertical barriers to flow. Cross-well interference testing proved that some of these barriers are discontinuous and act as baffles. Mobilities obtained from the MDTs, mimicked permeability contrasts measured in core. These contrasts confirmed the rapid response time seen in the cross-well interference tests. A full field simulation model with local grid refinement was able to match the cross-well interference test data. The integration of core description, whole core/plug physical properties, downhole electrical images, NMR, conventional logs, mobility, down-hole vertical as well as cross-well interference tests is presented and their impact discussed. Introduction Three gas injection pilots are commencing in three reservoir units (A, B & C) of this giant Middle East limestone field, currently under mature waterflood. The size of the pilots themselves could equal a full field development in many medium sized fields world-wide. Ten new wells and 10 existing ones form part of the pilot with well-spacing being generally 1km. The objective is to evaluate the benefits of gasflooding under secondary and tertiary conditions. This will allow major investment decisions to be made in the long-term full field development plans. One of the key uncertainties in gasflood performance is reservoir sweep. Vertical barriers and lateral conduits will control reservoir sweep and how well the injected gas can recover much of the remaining oil. Since there is no evidence of fractures in core where the pilots are targeted, the flow descriptions begin with predicting matrix permeability at the wellbore. This is extremely difficult in carbonate reservoirs and many attempts in the past have failed. However with suitable integration of all the static and dynamic data and careful upscaling to retain the contrasts described, it is possible to be predictive with a better level of confidence than previously experienced in this field. Observations on core permeability contrasts using core description and logs are extended to non-cored wells. At the wellbore vertical barriers are confirmed with MDT vertical interference testing. Lateral continuity of these barriers is not supported by inter-well interference measurements. This paper reports on the findings from the largest of the three pilots, Pilot C (6 new wells and 6 existing ones). The discussion however extends into the upper reservoir zones in the same wells. Even though the gas pilots in those zones are 5 km away, the trends seen are similar. The detailed core description is focussed on one key observer well Z16. Lateral trends are discussed briefly using other well data.
This paper sheds some light on the emerging EOR recovery mechanism related to modified ionic design of the injected water, sometimes referred to as low salinity or smart water EOR process. Many laboratory water-flooding experiments have been conducted with mixed outcomes on the benefit of the technology. Relative to the existing field applications in sandstones, this technology is less mature in carbonates. Many researchers support the theory that this process is very complex in carbonates and chemical reactions within productions time-scale are not well-understood. The literature lacks the connection between what researchers address in laboratory work and considerations for full-field applications. Therefore, this work aims to bridge some gaps between what is considered in experiments and what is relative to full-field applications. The paper offers a comprehensive review of the risk management framework related to the application of Low Salinity EOR process in offshore carbonates reservoirs in the UAE. Some risks/opportunities related to subsurface, flow assurance, surface facilities and operations will be addressed. The work presents an example of a risk matrix and remedial actions that must be considered during the design phase. For example, the root causes of souring, scaling, anhydrite participation, nepthenate solid precipitation and divalent cation migration will be presented and their possible impact on flow assurance will be addressed during the application of the low salinity flooding on different types of carbonate rocks. Furthermore, uncertainties related to pore-volume contact to reach the threshold salinity, temperature/cooling impact and chemical modelling limitations are addressed and related to the quantifications of the technology benefits as the study evolves from lab work, field trials and eventually to full-field applications. With such visibility of the full spectrum of the technology impact, laboratory experiments can be tuned with the focus to minimize specific risks and maximize benefits to the addressed field.
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