The objective of this paper is to demonstrate the design ingenuity and methodology used to complete a unique HIPS system, which was approved and chosen over the conventional and expensive Full Flare System solution for offshore unmanned high pressure gas production facilities. Some special design features were implemented to fulfill the Safety Integrity Level (SIL-3) requirements and ensure high level of protection for personnel and facilities. Additionally, this paper will illustrate the challenges for facility operators to preserve the HIPS integrity level throughout the lifetime of the facilities.

Risk is theoretically described as any potential deviation from the predefined target with its defined specifications. It is normally linked to terms such as issues, uncertainty, unknown etc. With dynamic situations involving unknown factors which can have pleasant or unpleasant, and mostly unforeseen and unpredictable consequences. Project risk management is the art and science of identifying, assigning and responding accordingly to the risk throughout the life of a project and in the best interests of meeting project objectives and goals. Risk management is often overlooked on projects, but it can help improve project success by helping select good projects, determining project scope and developing realistic project targets.

Well Integrity Assurance is the key concept to reduce the risk of unwanted incidents in any oil & gas field, thereby ensuring safety of people, environment, assets, business and reputation during the entire well life cycle from Conception to Abandonment. Due to a huge number of wells and the ever-increasing matured field issues, the key challenge faced by Qatar Petroleum was to prioritize the remedial measures (rig & rigless) and pro-active health checks based on well risk conditions and barrier status. In this paper, we are elucidating the Risk Assessment Suite created by the Well Integrity Department of Qatar Petroleum to resolve this challenge. The Risk Assessment Suite is an innovative model to assess the integrity issues in oil/gas wells, to establish their associated risk level and to prioritize the mitigation measures/pro-active health checks in those oil/gas wells based upon the risk level and optimum available resources for ensuring that the wells operate in a safe operating envelope. The four major components of the risk assessment suite are Risk Ranking Guidance Matrix, Well Failure Matrix, Priority Ranking Matrix, and Well Risk Assessment Sheet. The Risk Assessment Suite is a highly successful methodology practiced in Qatar Petroleum for assuring safety, well integrity, higher return on assets and performance enhancement of its oil & gas fields. The highlight of this suite is its unique innovative model for prioritizing the rig/rigless repairs and pro-active routine/non-routine health checks by considering priority ranking points together with risk ranking as a single function in order to address both risk level and the barrier failure intensity of a well at the same time. Risk Assessment Suite is a highly transferable model that can be used by other E&P companies worldwide with similar requirements like Qatar Petroleum for prioritizing remedial measures and risk mitigation actions on oil/gas wells in their fields.

This paper aims to serve as a guideline to more proactive risk evaluation and management. Each firm is supposed to have certain amount of systematic (undiversifiable) and idiosyncratic (diversfiable) risk. By the very definition of systematic risks, it is inherent to the firm because of the industry it operates in. However the idiosyncratic risk keeps changing because of various decisions that the firm makes, including portfolio decisions. The paper proposes a technique to isolate the idiosyncratic risk of a project/business in a firm from the global portfolio of the firm. It focuses on quantifying this idiosyncratic part of geopolitical and regulatory risks. The idea is to use this quantifiable risk to understand the effective cost of capital for the project, and hence equip the project manager with a tangible decision tool for risk prioritization and mitigation, and portfolio management. The proposed framework has a broad range of applications across a multitude of projects (field operations, manufacturing, logistics etc.) and geographical locations. The framework first identifies risks to any project using a risk assessment framework. These risks are then quantified using risk likelihood and impact factors resulting in a risk index for the project. This risk index is used to modify the Capital Asset Planning Model (CAPM) by varying the beta of the equation in order to come up with a new risk-adjusted cost of capital of the project. It also briefly touches upon quantifying risks in a more dynamic setting during the running of the project. The framework is tested on a hypothetical project in the MENA region to show its application. In case of a project that is ‘riskier’ than the firm's average project, the cost of capital for the project increases after the framework is applied - thereby reducing the net present value (NPV) of its cash flows, and making it less attractive.

Uncertainty in reserves estimation plays a critical role at all-time steps of production/development plans and determines the financial strength of the project and the company. In this study, the importance of probabilistic approach to reserves estimation is emphasized by showing change in the estimated values of reserves with producing time. An analytic uncertainty propagation method (AUPM), a simple, yet quite accurate alternative uncertainty quantification method to the well-known Monte Carlo method, is used to assess the uncertainty in gas reserves estimations. In addition to the theory, as a case study, one of the largest Turkish Petroleum Corporation (TPAO) gas field, Çayırdere Field, reserves is estimated, and uncertainties for this field reserve are presented at all-time steps. As a result, the estimated value of the most likely reserve (P50) by utilization of AUPM in conjunction with probabilistic methodology prior to production period, matches quite well with the value estimated at the abandonment of the reservoir by using performance-based methods. The Çayırdere Gas Field Case Study supports the glorious success of the approach promised in this study.

Traditionally in desert operations in Libya, drilling mud and cuttings (water based) have been disposed of directly on the ground in unlined pits. This practice has lately been challenged because other than affecting the landscape, it can pose a risk to the soil and to shallow aquifers. To correctly assess the risk that this practice poses, REMSA and specialized environmental consultants developed a tool to predict the risk of pollutants transported by lixiviates reaching shallow aquifers below the drilling pit itself. The model has the capacity of determining the threat of a group of pollutants individually moving from the pit through the Unsaturated Zone. Other than modeling the movement driven by gravity, the model also considers biodegradation of organics and absorption processes within the Unsaturated Zone and dilution once in the Saturated Zone. This modeling tool (CREWD) has been tested in block NC186 in Libya and the results have been validated throughboreholes and excavations that reached down 4 meters below the bottom of the pit. The results obtained using the model, gave a clear indication that with the prevailing conditions in NC186 and knowing that the shallowest aquifer mapped is below 60 m depth, the risk of hydrocarbons, heavy metals or salts causing detrimental impact to the aquifer is extremely low.

Description Effective Management of the Contractor HSE performance starts from an Effective Mitigation of risks in the Tendering Process. In Contracts for Oil & Gas Industry, the work force was mainly Company employees and since 1990 there has been a significant increase in the use of contractor staff which resulting shift in responsibilities/risk from the company to contractor. International Association of OIL and Gas Producers (OGP) published "HSE Management Guidelines for Working Together in a Contract Environment" (Report No. 6.64/291, September 1999). Most Operators’ HSE Management Systems follow these Guidelines. Application Is the following sentence is true? "There is a very little that Contracts Professionals can do to drive the Best Safety & Environmental Performance on Site." If it is true, HOW can they do it? Is this a paradigm that they should challenge? How risk assessment is performed and how results are translated into Practical Contract Strategy? Results, Observations & Conclusions Results: As per the summary of OGP Guidelines for Contracting Process. Most current Contract Strategy Decisions and Most Operators’ HSE Management Systems are based on detailed Risk Assessments of each generic operation in addition to generically control many different tasks/operations. Generic contract standards are tailored to and available for different types of work and services Observations: Intent of OGP Guidelines. Is it sufficient to adopt a generic process for risk assessment & evaluation of Contractor HSEMS? What should our Risk Assessment focus on? Will such a generic process automatically identify & mitigate the most critical HSE risks, specifically relating to a Scope of Work? Should the degree of rigor with which we approach HSE risk mitigation be linked to the overall magnitude of risk associated with a particular Scope of Work? What is the most important strategic contract decision to be made by the Company? Samples of Contracting Strategy Modes. Conclusions: A Focused Approach to HSE Evaluation shall be developed and implemented. Develop Specific Contract provisions that will drive a "Technically Acceptable" contractor to improve his HSE performance Significance of Subject Matter Contracts Professionals can do the followings to drive the Best Safety & Environmental Performance on Site: Include a step in the Tender's process requiring specific technical outputs from Risk Assessment (for input into Tender requirements) Include a step in the Contract award process requiring specific technical output from HSE evaluation (for input to final contract) Management of HSE in a business environment where two or more companies work together requires co-operation between them and a clear definition of the tasks and responsibilities of each of the parties.

Abstract The last few years have seen a renewed emphasis on Well Integrity (WI) worldwide, and ADMA-OPCO in particular. ADMA operates, more than 600 wells, in two offshore fields, which include oil producers, water injectors, gas producers/injectors and observation wells. A dedicated team was setup to focus entirely on WI and related issues. The team was given the objective to achieve the following. -Determine the Well Integrity Status of the entire well stock through risk review and ranking. -Recommend appropriate action plan for each well with unacceptable level of risk. The team used a comprehensive and novel approach for handling this project. This paper is a case study of the methodology adopted by the team to achieve this task. Since the main objective was to risk review and rank the entire well stock, a dedicated risk-ranking process was designed, which served as an automatic guide to risk review and ranking of wells. The industry Risk Ranking matrix was modified to make it more objective and easy to use. It soon became obvious that risk evaluation of wells was only possible based on availability of good data organized in a user-friendly format. A dedicated database was setup in parallel with other activities. The web-based database was designed to contain all the data required for WI review of any well and is capable of tracking well integrity related tasks automatically. Well Integrity data included well construction, annuli pressures, production, well intervention, etc. The data existed in the office files were promptly transferred into the database. The team made a strong effort towards building the capabilities to acquire missing WI data such as Annulus Leak Rates, Integrity Test Results, Wellhead and Xmas Tree status. Annulus leak rate measurement skid was designed and built, in-house. One-off contracts were established to hot tap blind-flanged annuli and to perform Xmas tree and wellhead inventory survey and cavity checking/testing. A completely new system of WI certification has also been established. So far, the team has successfully reviewed and risk ranked majority of the wells in the two assets of ADMA-OPCO. Introduction: Well integrity is a growing concern in the oil industry. Years of cheap oil had placed this aspect of the oilfields on a back burner. Oilfields, specially the bigger ones are maturing and presenting new challenges by way of risk management.

Abstract Saudi Aramco is continuously implementing many new innovative techniques and approaches to assist in meeting the industry's increasing challenges. One of these innovations is the new study approach "The Event Solution." Theapproach leads to better synergy among different stakeholders and enables faster decisions that fully encompass the complex uncertainties associated with today's projects. The Event Solution is a short, intensively collaborative event that compresses major decision cycles, reduces uncertainty and provides a wider range of alternatives solutions. The concept is simple: identify the most important objective and focus the collective skills and creativity of a team of experts on meeting that objective in a special event that lasts just for a few weeks. The team is enabled with the latest hardware and software in a large team room where they can work together. A facilitator leads the team with the process that helps them to see "The Big Picture" and understand what matters to the bottom line. The team composition is enriched with representatives from all of the stakeholders (including technical experts, management, and facilitators) so that the results can be concluded and implemented immediately, with maximum buy-in. The Event Solution includes a detailed uncertainty analysis and risk assessment process that has been successfully implemented in many events. The most important deliverable of the Event Solution, however, is that all the stakeholders develop a clear and common understanding of the critical uncertainties, project risk, and the agreed plans to move forward---the decisions. This volume of work, which traditionally requires months or years, is completed in weeks using the Event Solution process. This paper presents the elements and processes of this new approach. Critical elements to a successful Event Solution include software, workroom, team members, and a facilitator. Once the elements are in place, the facilitator leads the team through processes that include project preparation, parallel workflows, uncertainty analysis, critical information plans, project risk assessment, and mitigation plans. Note that uncertainty analysis is not a simple by-product of the study; it is an integral component of success. Techniques are presented that can be applied to any study. Introduction Oil and gas producers are familiar with the performance improvement that multi-discipline teams can contribute to the industry. Joeseph Warren notes that the success of individual team can be variable when he states, "the fundamental idea of cross functional teams and goals appears to surface about every 10 years with a new label. Usually, attempts to implement this concept in the E & P business ended with utter failure for a variety of reasons." 1,4 The Event Solution extends the multi-discipline team concept by formalizing key success factors: identifying the most important objective, focusing the collective skills and creativity of a team of experts on meeting that objective, and collaborating via a special event that lasts weeks rather than months or years. In the 1980s the concept of asset teams was introduced. Unfortunately, integrated software was too immature at that time to enable real integration of the asset team members. As integrated software became more powerful in the early-to-mid 1990s the asset teams began showing more success. In the late 1990s, common processes were adapted by most major oil and gas companies to ensure repeatable success from team to team. Highly formalized processes, often employing gatekeepers, were developed to integrate the management (decision makers) and technical (asset) teams.

Abstract One of the greatest challenges facing petroleum companies today is how to prioritize projects such as drilling wells based on the likelihood of profitability. To accomplish this, the risks associated with each project must be fully assessed. Risk assessment is particularly important in complex, mature offshore fields which have already been drilled up and where the cost of further drilling is high. Drilling prospects in such fields may involve targets that are updip of current wells, at locations that are difficult to reach from existing platforms. Reserves are predicated upon the prognosed locations of sealing faults and upon assumptions about drainage patterns in the area. All of these factors make the assessment of all risks and an understanding of the range of parameters that affect reserves extremely important. A specific example from the Nubia C Formation in the Ramadan Field, one of GUPCO's most mature water drive oil reservoirs in the Gulf of Suez, is used as an illustration of how to address and to quantify risks. Several factors, including the likelihood of drainage by existing wells, the location of faults in the area, and structural character are quantified. Ranges for drainage volume, recovery factor, water saturation and porosity are incorporated as distributions in the assessment. The results of this work are a figure for risk-weighted reserves and a probabilistic rate profile which can be used to determine the economics of the project. Introduction Many of GUPCO's fields in the Gulf of Suez are very mature. For the Ramadan Field, one of GUPCO's most mature fields, the primary production zone historically has been the water drive Nubia C reservoir. This field is complex, having multiple fault cuts that are difficult to map completely, despite many penetrations over the years. Since wellbores are typically located at the top of the structure and the well paths are constrained by existing platform locations, reaching the remaining reserves at updip attic locations even closer to the faults than existing wells is very difficult and extremely expensive. Until recently the approach to determining whether to drill a well in Ramadan was been based upon economics generated by deterministic values of rates, reserves and costs. However, this approach led to several unsuccessful drilling wells, and it was clear that a better method of making decisions was needed. Over the past year, a new risk-weighted approach has been fashioned to assess the rates, reserves and, consequently, the economics of potential drilling locations. This approach involves defining distributions for volumetric parameters such as drainage area, porosity, net pay thickness and water saturation and determining other risk factors such as location of the updip fault, height above existing wells and drilling cost. Any desired parameter, including individual zone reserves, frequency of occurrence of any particular event as well as rates and reserves, can be forecasted. This PC-based technique generates not only risk-weighted mean values of forecasted parameters but also a distribution of possible outcomes. This type of information is extremely valuable both to the technical team and to management for making drilling decisions. Risk assessment for the sidetrack of Ramadan Well 33 (R6-33 S/T), which is detailed here, is an excellent example of this type of approach. The drilling of R6-33 S/T was successful. The subsea elevation of formation tops was very much as expected and porosities and water saturations were within the expected ranges, and actual performance is substantially matching the risk-weighted rates. Most importantly, the story of this well demonstrates how this technique can be used to address drilling well prospects in a complex reservoir. Since this well was drilled, the technique has been updated and improved and is now being used to assess every major GUPCO drilling prospect. P. 205^

SPE Member Abstract Jebel Dhanna is the only terminal for storage and export of the onshore oil production of Abu Dhabi Emirate. Crude oil flows from the tanks farm via two 48 inch gravity loading lines to the foreshore area where it is boosted by pumps to the loading berths. The two gravity lines are needed for export at peak capacity and also for implementing the crude oil re-circulation plan in an emergency. Due to the age of the piping system, a risk assessment study was conducted to evaluate the need for a new gravity line. Introduction Jebel Dhanna is the only terminal for storage and export of the onshore crude oil production of Abu Dhabi Emirate. It is situated on the coast some 250 km west of Abu Dhabi city (Figure 1). The terminal was originally constructed in 1962 with six tanks, each 50.3 in diameter and 19.5 in high. Seven more tanks, each 79.2 in diameter and 19.5 in high were constructed between 1968 and 1973. All 13 tanks have a common base which is at an elevation 64.1 in above sea level. The total storage capacity of the tank farm is 5.7 million barrels. Crude oil flows from the tank farm through two 48 inch gravity loading lines to the foreshore area where it is boosted by the loading pumps to four marine berths. Three more tanks have been recently constructed and are being commissioned at the time of writing (Figure 2). Each tank has a diameter of 102 m and a height of 19.5 m. This will bring the gross capacity of the tank farm to 8.7 million barrels. EMERGENCY TRANSFER PLAN The emergency response procedures (1) have been developed to deal with an emergency such as a fire, severe leak or a spill in the tank farm. In the event of a fire in a tank, the crude oil in the surrounding tanks is transferred to other storage tanks further away from the fire. This is to prevent the fire from spreading and eventually destroying the entire tank farm. The transfer of crude oil is achieved by controlling the inlet and outlet valves to the tanks and recycling the crude oil via one gravity line to the foreshore area and then pumping it through the other gravity line to the tank farm again (Figure 3). Alternatively if a tanker is available at berth, the crude is transferred into it. The sequence of action to be taken during the predefined emergency situation has been programmed in the computer. The interactive menu is available to the operator at the work stations in the central control room. CORROSION IN THE PIPING SYSTEM The majority of the piping system in Jebel Dhanna is buried. This includes the tank farm piping, the two gravity lines and the foreshore area piping. P. 383^