Identification of the source of pressure communication between well tubing-casing and casing-casing annuli presents an enormous challenge to petroleum engineers. Qatar Petroleum recently field-tested an acoustics based tool to successfully pinpoint the source of high pressure in the tubing casing annulus in a deep gas well in an onshore field. This paper presents a description of the technology and the findings from the field trial. An ultrasonic leak detection tool has been developed for down-hole applications to take advantage of the unique properties of ultrasound energy propagation through various media. This data acquisition equipment has been developed to allow continuous logging SRO (Surface Read Out) operation on conventional electric line or memory mode on slick line. The movement of fluids across a failed barrier creates turbulence which in turn creates ultrasonic frequency sound waves that are detected by the tool sensor. This new tool is different from the conventional noise logs as its' highly customized multiple sensitivities enable the detection of leaks as small as 0.02 Litres per Minute (LPM) with an accuracy of inches in the production tubing, casing and other completion equipment. It is also practically immune to disturbances from distant noise sources. The tool was run in a deep gas well with a history of high pressure in the tubing-casing annulus. Diagnostic work prior to the trial had established that the wellhead seals were not the source of the pressure. A leak rate of 3.5 LPM was estimated based on the pressure build-up trend in the annulus. The paper describes the procedure for running the survey and discusses the interpretation of the results that confirmed a casing leak at a failed recirculation valve (DV). The field trial confirmed that ultrasonic based well leak detector can accurately and efficiently detect very small tubing and casing leaks. Introduction: A growing concern in the life of an oil or gas well is the pressure buildup in its annuli. The first challenge for a petroleum engineer is to identify the source of the leak to enable design of an effective remedial activity. There are many methods to identify the source of leaks in a well. The simplest, cheapest and most common is the "Pony Tail" method. If the leak is big enough (>100 LPM), flowing from the tubing into the A-annulus then a highly experienced slickline operator running a "Pony Tail" assembly may be able to detect the leak location. This method will, obviously, not work with very small leaks. More advanced technologies have been used over the years to identify such leaks more accurately. Over time, a philosophical approach has been used to decide what technological gadget to use. Temperature logs, spinner logs, downhole cameras, and noise logs, etc. or a combination thereof can help identify rather small leaks (with leak rates varying between 10 LPM and 100 LPM) between the tubing and A-Annulus. The optimal tool string depends in part on the magnitude of the leak. At the lower range of leak rates, the noise log is often the most sensitive. The temperature log works over a broader range of leak rates, but is usually not as sensitive as the noise log. A spinner can be used for higher leak rates.2 The problem becomes more complicated when the leaks are caused by packer (seal element) failure or holes in the casing causing fluid movement from the B-Annulus to A-Annulus, or fluid movement from the formation through the annuli and reaching to the A-Annulus. (i.e. problems behind the tubing wall). Matters are further complicated if the leak rate at the time of investigation is lower than the sensitivity of the tool being used for identification. Based on extensive R&D in the ultrasound technology domain, it was discovered that an active leak at rates ranging from 0.02 LPM to 150 LPM would create turbulence with a high frequency wave that would generate an ultrasonic signature.

Hydrochloric acid (HCl) is commonly used to remove wellbore damage and to enhance near-wellbore formation permeability in carbonate formations. Although in most cases the spent acid is recovered rapidly during well flow back after the treatment, in heterogeneous reservoirs some of the spent acid can remain trapped for long periods becoming fully saturated with CaCO 3 under downhole conditions. These reservoir-saturated spent acids then lead to scaling when eventually unloaded into the production system. This paper describes a modelling and laboratory study to replicate the system, to allow selection of inhibitors which are effective against carbonate scales in spent acid solutions containing extremely high levels of Ca 2+ /Mg 2+ , and also remain stable at elevated temperatures in the spent acids. The work also examined chemical retention and release via coreflood testing followed by field application modelling to select effective scale inhibitors (SI) which possess poor retention properties on the carbonate substrate thereby remaining present in the "spent acid". One significant challenge associated with this study was the ability to reproduce the mildly oversaturated field scaling environment in the laboratory. When using these fully saturated (with respect to CaCO 3 ) partially acidic brines, very small changes in the brine chemistry or preparation procedures had a significant impact on scaling. A detailed evaluation of brine preparation, stabilisation and buffering was therefore required prior to evaluating generic scale inhibitors for performance under these extreme conditions leading to selection of appropriate species. The second stage of the work then involved core test procedures to determine those chemicals that offered minimal retention properties on the reservoir along with performance. This paper will present the field scaling challenges observed due to unloading of trapped spent acids; describe challenges faced within the laboratory in reproducing these conditions and present results from generic chemical types which are effective at preventing scale under these extreme conditions. From the shortlisted products further results are presented demonstrating those which offer poor retention, which is generally the opposite of what is required for conventional scale inhibitor squeeze treatments, allowing selection for upcoming field trials in the selected field system.

Inspection of the below grade well head equipment has shown corrosion damage to the buried landing base, casing spools and surface casing, especially in water injection and supply wells in onshore fields in Saudi Arabia. This paper describes the problem, examines possible reasons for the occurrence of corrosion and then discusses procedures and standards that have been developed to regularly inspect all wells, perform the required repair work in a safe and cost-effective manner and provide durable protection with field-applied corrosion resistant coating on all buried equipment. Introduction Occurrence of corrosion damage in the buried well head equipment and surface casing immediately below the landing base has been a concern in the onshore fields in Saudi Arabia. Initial random inspections of the below grade wellhead equipment in the mid-eighties showed corrosion damage to the buried landing base, casing spools and surface casing. The damage was occurring in spite of an apparently successful cathodic protection program that has reduced the number of casing leaks due to external corrosion damage. The possible causes of the corrosion damage are: leakage of water from surface piping and wellhead valves during various operations on water related wells, presence of highly saline and corrosive water close to surface in "subkha" terrain, and, impediments to effective cathodic protection at shallow depths. In view of the safety and environmental hazards associated with possible shallow leaks from corroded casing or failure of wellhead equipment, a number of steps have been taken to control the damage. These include regular inspection and repairs at regular intervals, protection with field-applied corrosion resistant coatings and a requirement to coat all new wells immediately after the rig release. Regular inspection and protection of the below grade wellhead equipment has successfully reduced potential hazards associated with casing failures at shallow depths. Repair and renovation costs have been effectively reduced by establishing guidelines for safe acceptable thickness limits and by adopting rigless repair procedures. Problem Description Typical landing base and surface casing equipment for onshore wells is depicted in Figure-1. The 13-3/8" casing is either welded or screwed on to the 13-3/8"x13-5/8" landing base. The 18-5/8" conductor pipe is cemented at a distance ranging from a few inches to 2–3 feet below the landing base. A typical landing base inspection operation involves excavating the cellar to below the landing base to expose three to six feet of the surface casing or until hard cement is encountered below the landing base, which ever is earlier. The exposed section is sand blasted and then inspected for evidence of corrosion. The data from such inspections for the last six years (1991 through 1996) is presented in Table-1, while Figures 2 through 4 illustrate some cases of severe corrosion damage on the landing base and surface casing on oil as well as water wells. P. 283^

Production of high salinity formation water with gas presents major operational and reservoir management challenges in gas reservoirs. Early detection of unexpected water production is critical for ensuring prompt action to prevent accelerated corrosion damage in surface pipelines and facilities if they are not designed to handle the produced brine. Several methods exist for detecting water in pipelines which are based on electrical, electromagnetic, and acoustic measurements. While most of the existing methods are intrusive requiring direct contact between the measurement probe and the flow stream, all such methods suffer from low accuracy of measurements and dependence on water composition and salinity. This paper reviews the various technologies that are in use to detect and measure water production. It also describes the theoretical background and the laboratory testing of a new means for detecting presence of formation water in gas flow lines.1–10 This work is part of a joint collaboration between RasGas Company Limited and Texas A&M University at Qatar (TAMUQ) aimed at developing a device which is: non-intrusive, clamp-on externally on the flow-line, accurate, and independent of saline water composition. This technology is based on neutron elastic-scattering and activation interactions. The laboratory testing is performed using simulated field conditions to determine the feasibility and accuracy of the measurement technique. Based on the laboratory results, a prototype device is planned to be constructed for field testing. Safety aspects of the process application both in the lab and in the field have been thoroughly examined and comprehensive safety measures have been developed and implemented per the health and safety regulatory requirements. The paper also presents the findings from a simulation study using the Monte Carlo N-Particle (MCNP5) neutron flux simulator11 to examine the feasibility of the proposed method and to properly design and optimize the experimental setup and procedure. Introduction Produced fluid in gas fields consists, generally, of gas, condensate, and condensed (zero salinity) water. As production progresses, formation saline water (brine) can be produced with the condensed water. This can affect the operation and safety of the production system by accelerating corrosion and scaling potential, especially in the presence of acidic gases such as CO2 and H2S and the inorganic salts dissolved in the brine. Brine can also lead to emulsion and bacteria related problems. Therefore, it is very important to detect the presence of formation brine in the system as soon as it starts to be produced.

This paper will discuss the findings from a field trial to evaluate the reliability of a retrofitted acoustic data acquisition system in an onshore well in Qatar for a three month period. The technology allows downhole data to be transferred from multiple locations in the well tubing to the wellhead utilizing acoustic waves. From the wellhead, the data is transmitted to engineers PC through a satellite communication system. This technology eliminates the need for expensive hardware or fiber optic cable used in the conventional downhole monitoring systems. The field trial was successfully completed after 111 days of continuous data gathering and monitoring. All P/T gauges and the acoustic data transmission devices installed in the well performed excellently. The objectives of the trial were achieved. We not only were able to collect the downhole pressure and temperature data for well performance analysis but were also able to define the flow patterns (such as the slugging effects) occurring in the well due to changes in bottomhole pressure. This system can be deployed as a temporary installation retrofit in the existing wells utilizing conventional wireline units, or permanently as part of the well completions for monitoring well performance for reservoir management or well performance monitoring purposes. The trial did not cover evaluation of the system under permanent installation mode as part of the well completion. Permanent installations can be considered once more long term experience has been gained from retrofit applications. IT involvement to provide support and the data transmission link is very essential. The paper will describe the overall system, illustrate the quality and accuracy of real time data obtained during the trial and its utilization for well and reservoir performance evaluation purposes. Introduction Completed wells and producing fields often develop problems that were not foreseeable at the completion design stage. When wells, without permanent downhole pressure monitoring, experience a surface pressure decline combined with reducing or varying production rates, surface production data alone may be misleading. The traditionally accepted diagnostic procedure would be to perform static and flowing gradient surveys but that can show only a snapshot of the wellbore conditions. Indeed, if the well is slugging, a conventional gradient survey may in itself create changes in the wellbore conditions and lead to erroneous assumptions. What may be required is to monitor the downhole gradient over an extended period, without continuously disturbing the well by repeated wireline intervention. A national oil company, in the Middle East, operates an established oil / gas producing field, with water injection pressure maintenance. One of the wells died for no obvious reason. After side tracking and re-completing the well, production was resumed but, after four months, the well died again. Static gradient surveys were performed one month and six months after ceasing production, which showed that the well was slowly regaining pressure but still would not flow. With recent advances in the reliability of acoustic data transmission systems, improved data transmission rates and longevity of battery operated devices, the technology now exists to retrofit existing completions with permanent or semi-permanent downhole sensors and transmit the recorded data to the surface completely wirelessly. The data transmitted may be any parameter that can be recorded downhole, such as fluid density, capacitance, viscosity, sand detection, corrosion monitoring or, as in this trial, pressure and temperature. In addition, as the communication is two-way, the system can be used to control downhole devices, such as valves, sliding sleeves and bottom hole samplers. A proposal was made to the client to demonstrate the capabilities of this system in this well by installing pressure and temperature gauges and acoustic relay tools temporarily in the well for a three month trial. The purpose of the trial was to allow the client to evaluate the system prior to considering it for wider application in new and existing completions.