Summary One of the most important but least well-known parameters in cementing operations is the circulating temperature. Many authors have presented theoretical analyses of the wellbore conditions, formulated mathematical models, and presented actual field measurements. However, very little temperature data have been reported for conditions of greatest concern (i.e., with casing in hole). To gather such data in detail, circulating temperature and pressure measurements were made with downhole tools lowered on wireline. In one case, temperature measurements were made during circulation immediately before cementing to record the circulating temperature in the well. In another case, measurements were made after the slurry was been placed to record the thermal recovery of the well. Data collected during these field trials (with casing in hole) are presented and demonstrate the different thermal response of a well with casing instead of drillpipe in the hole. Measured circulating temperatures are lower than those derived from the API schedules and highlight the necessity to account for well geometry properly when determining downhole temperatures. Introduction The oil industry has long recognized the importance of accurate and reliable determination of downhole circulating temperatures with respect to cementing operations. This is amply illustrated by the number of papers published on the subject. A number of analytical and numerical methods have been proposed to model the circulating well that often quote field data collected under drilling conditions. Various tools have been proposed for downhole flowing temperature measurement, and field data have been presented that show temperatures measured with drillpipe in the hole. However, very few papers have reported field data under the conditions that are most important (i.e., circulating temperatures with casing in hole). This paper presents the results of two field trials where fluid temperatures have been measured either at the casing shoe just before or immediately after the placement of a cement slurry.

In the Al Shaheen (ALS) field offshore Qatar, injection wells have generally been back-flowed to remove solids introduced during drilling and stimulation, with the objective of enhancing injectivity. This is considered by many as "best-practice" in the industry. Data from the early back-flow period for injectors and the early production period for producers has been reviewed to try to identify "clean-up" events. Some apparently spontaneous rate increases were observed. Analysis of this data was found to be complicated because during the initial 20 days of production frequent choke size changes were made. Bottom-hole pressure data around the time the wells were opened was also found to be absent in most cases. An attempt to compare the injectivity of a few wells which were not back-flowed with analogues that were was also frustrated, due to variability of permeability and oil viscosity between wells. It was not possible to draw definitive conclusions. A new phase of drilling at ALS provides an opportunity to investigate the efficacy of back-flowing in a pre-mediated fashion. Special provisions will be made during the initial production period to evaluate whether or not the wells clean up. In addition a comparison will be made between the injection performance of pairs of injection wells which are located in areas with similar transport properties. For the injection well pairs, one injector will be back-flowed for a month while the other will be put on injection immediately after stimulation. In this manner it is hoped to demonstrate conclusively whether back-flow of ALS injectors enhances injectivity. Introduction Historically, most Al Shaheen (ALS) water injection wells have been back-flowed before conversion to water injection. Back-flow was done to "clean-up" the injectors and also to produce oil revenue. This paper reviews the possible benefits of back-flow, based on experience with existing wells, and describes steps that will be taken in future to determine the effect of back-flow in a few wells in a carefully controlled environment. The wells in this future trial of back-flowing will each have a "control" well that will not be back-flowed before water injection starts. Although many ALS wells showed apparent "clean-up" events in their early production, it is by no means certain that there was a lasting improvement. The results of back-flow were hard to analyse because, during the early days of back-flow when "clean-up" events were expected to occur, the choke settings were often being changed. In addition, many water injection wells either did not have down-hole pressure gauges, or do not have detailed pressure records to permit more complete analysis of the back-flow period. The back-flow of future water injection wells will generate less revenue than previous back-flow because the new injectors will be in deeper layers and are expected to produce some water almost immediately. Acid stimulation was conducted for the past wells, and this process is considered sound and will be continued. Back-flow is estimated to add some $700,000 to the cost of a water injector because a full production hook-up, including lift-gas, is required. This cost will, however, be more than justified if a 5% increase in injectivity can be shown to result from back-flow.

An opportunity to establish a certain level of confidence in the well models by analysing entire production history or even performing analysis in real time becomes a reality of today. This paper is intended to describe an engineering approach to the analysis that was tailored to the Al Shaheen field to better understand the well performance, gain confidence in the models and identify various well issues and opportunities. The challenge of understanding how wells perform is always associated with comprehensive data mining and significant time spent on analysis and calculations. However the data available is always limited and often requires quite a few assumptions to be made by an engineer when building a representative and reliable well model. All industry standard software packages utilise same or similar well-known concepts and types of analysis from simple equations to more comprehensive algorithms. These are like pieces of the puzzle that can be assembled together to help petroleum engineer to get an idea of how the well should perform in particular circumstances. The way petroleum engineers applying these concepts on daily basis may vary depending on the nature of the problem they are facing and the amount of data they have available. Quite often the fact that the model does not match the reality is used to invalidate existing data and an opportunity to understand that something is happening in the well that is not captured by the model is overlooked. Reasons for this may include an existence of a particular purpose of the well model, level of engineer's experience, skills or imagination, lack of required data or at the end an inability to process the entire production data in an efficient way. The last becomes a real challenge on the fields with large amount of wells and extensive production history. Synergy between adopted analysis and the technology has allowed engineers to gain a much better understanding of the well performance, identify various issues and opportunities and enabled them to keep focus on making decisions as to which wells to optimise and those to troubleshoot to maximise potential of the existing well stock.