Field A is a significant contributor within the Kaombo development project, offshore Angola. The field comprises five stacked sedimentary units (A1 through A5, from top to bottom) requiring openhole gravel packs (OHGP) as the sand control technique, and a commingle strategy was key to reducing well count. Production from reservoir A4 could not be commingled with that from other sedimentary layers due to the risk of asphaltene precipitation, and A3, water bearing in one panel, also required isolation. The openhole mechanical packer (OHMP) with OHGP completion was used in field A to reduce the well count from the originally planned eight oil producers (OP) to six OP; this brought savings in excess of USD 100 million. Well 1 in field A penetrates all five reservoirs; it was successfully completed in December 2016 with two OHMPs isolating reservoir A4. A well in field B was successfully completed in May 2017 with one OHMP to allow future water shutoff (WSO) with potential production acceleration as well as estimated ultimate recovery (EUR) increase of more than one million barrel of oil equivalent (MMboe). Downhole gauge data analysis combined with mass balance indicated that 100% pack efficiency was achieved in both wells with the expected packing sequence in the presence of packers bypassed with shunt tubes. The OHMP enhances the versatility of OHGP completions with eccentric shunt-tube screen assemblies, which enable applications such as selectivity, zonal isolation, and water shutoff. The robustness of OHGP completions together with the features mentioned earlier will improve the economics for future projects by reducing capital expenditure (capex) and increasing reserves recovery per well. This application was an important contributor to reduce drilling expenditure (drillex) for the Kaombo development project.

The analysis/interpretation of wellbore storage distorted pressure transient test data remains one of the most significant challenges in well test analysis. Deconvolution (i.e., the "conversion" of a variable-rate distorted pressure profile into the pressure profile for an equivalent constant rate production sequence) has been in limited use as a "conversion" mechanism for the last 25 years. Unfortunately, standard deconvolution techniques require accu-rate measurements of flowrate and pressure --- at downhole (or sandface) conditions. While accurate pressure measurements are commonplace, the measurement of sandface flowrates is rare, essentially non-existent in practice. As such, the "deconvolution" of wellbore storage distorted pressure test data is problematic --- in theory, this process is possible, but in practice, without accurate measurements of flowrates, this process can not be employed. In this work we provide explicit (direct) deconvolution of wellbore storage distorted pressure test data using only those pressure data. The value of this work is that we provide explicit tools for the analysis of wellbore storage distorted pressure data --- specifically, we utilize the following techniques: --- Russell method (1965) (very approximate approach). --- "Beta" deconvolution (1950s and 1980s). --- "Material Balance" deconvolution (1990s). Each method has been validated using both synthetic data and literature field cases and each method should be considered valid for practical applications (the Russell method was not used). Our primary technical contribution in this work is the adaptation of various deconvolution methods for the explicit analysis of an arbitrary set of pressure transient test data which are distorted by wellbore storage --- without the requirement of having measured sandface flowrates. Objectives The objective of this work is to provide a comprehensive study of the analytic techniques that can be used to explicitly deconvolve wellbore storage distorted well test data using only the given pressure data and the well/reservoir information. Introduction Previous Work: For the elimination of wellbore storage effects in pressure transient test data, a variety of methods using different techniques have been proposed. An approximate "direct" method by Russell (1966) "corrects" the pressure transient data distorted by wellbore storage into the equivalent pressure function for the constant rate case. Despite its simplicity, it has several shortcomings such as limited accuracy and erroneous skin factor estimation. In short, the Russell (1966) method should not be used. Rate normalization techniques [Gladfelter et. al., (1955), Fetko-vich and Vienot (1984)] have also been employed to correct for wellbore storage effects and these rate normalization methods were successful in some cases. The most appropriate appli-cation of rate normalization is its use for pressure transient data influenced by continuously varying flowrates. The application of rate normalization requires the sandface rate measurements and generally yields a shifted results trend that has the correct slope, but incorrect intercept in a semilog plot (incorrect skin factor). Johnston (1992) showed that "material balance deconvolution" is a practical approach for the analysis of pressure transient data distorted by wellbore storage effects. In particular, this approach remedies the issue of a poor skin factor estimate that is typically obtained using rate normalization. Material balance deconvolution is also though to require continuously varying sandface flowrate measurements. We will show that sandface flowrates can be approximated from the observed pressure data. Essentially, rate normalization techniques are restricted when the lack of rate measurement exists. van Everdingen (1953) and Hurst (1953) demonstrated empirically that the sandface rate profile can be modeled approximately using an exponential rela-tion for the duration of wellbore storage distortion during a pres-sure transient test. The van Everdingen/Hurst exponential rate model is given in dimensionless form as: (during wellbore storage distortion)..... (1)

The analysis/interpretation of wellbore storage distorted pressure transient test data remains one of the most significant challenges in well test analysis. Deconvolution (i.e., the "conversion" of a variable-rate distorted pressure profile into the pressure profile for an equivalent constant rate production sequence) has been in limited use as a "conversion" mechanism for the last 25 years. Unfortunately, standard deconvolution techniques require accurate measurements of flow-rate and pressure -at downhole (or sandface) conditions. While accurate pressure measurements are commonplace, the measurement of sandface flowrates is rare, essentially non-existent in practice.As such, the "deconvolution" of wellbore storage distorted pressure test data is problematic.In theory, this process is possible, but in practice, without accurate measurements of flowrates, this process can not be employed. In this work we provide explicit (direct) deconvolution of wellbore storage distorted pressure test data using only those pressure data. The underlying equations associated with each deconvolution scheme are derived in the Appendices and implemented via a computational module.The value of this work is that we provide explicit tools for the analysis of wellbore storage distorted pressure data; specifically, we utilize the following techniques:Russell method (1966) (very approximate approach), "Beta" deconvolution (1950s and 1980s), "Material Balance" deconvolution (1990s).Each method has been validated using both synthetic data and literature field cases and each method should be considered valid for practical applications.Our primary technical contribution in this work is the adaptation of various deconvolution methods for the explicit analysis of an arbitrary set of pressure transient test data which are distorted by wellbore storage -without the requirement of having measured sandface flowrates. iv DEDICATIONWe must never be afraid to go too far, for truth lies beyond. -Marcel ProustHe who loves practice without theory is like the sailor who boards ship without a rudder and compass, and never knows where he may cast.-Leonardo da Vinci v

The FPSO Kaombo Norte came on stream on July 27th offshore Angola. When both its FPSOs will be at plateau, Kaombo, the biggest deep offshore project in Angola will account for 15% of the country's oil production. It produces light oil from six fields scattered over an 800-square-kilometer area. Gindungo, Gengibre, and Caril fields are connected to the Norte FPSO while Mostarda, Canela, and Louro fields will be producing on FPSO Sul. The full development stands out for its subsea network size with more than 300 kilometers of lines on the seabed within 1500-2000m water depth, including subsea production wells more than 25km away from the production facility. In order to secure a safe First-Oil and to smoothly start-up the production, a detailed and cross-functional study was carried out. The first step was to start from a clean slate by forgetting all previous startup scenarios: the three loops candidate to start-up hydrocarbon production were re-analyzed in depth to evaluate strengths and weaknesses. A task force composed of all involved disciplines, including contractors, was put in place in order to apply a cross-functional approach. Constraints from reservoir up to topsides were analyzed providing an overall picture and clear ranking to develop the start-up strategy. An ambitious planning of the commissioning activities combined with a relatively short-term reservoir management were crucial to lock production loop priorities with water injection and gas export systems readiness. The work jointly performed contributed to serene environment for a safe start-up and ramp-up. Following the assessment, decision was made to start first the most "powerful" reservoir despite a challenging flowline. The relatively high initial pressure and oil undersaturation, the robust open-hole gravel-pack completions and high productivity wells were beneficial to stabilize the multiphase flow in the subsea network. Improvement of the production was rapidly made with the start-up of the second production loop only fifteen days after. Postponement of the water injection system and the availability of the riser base gas lift were judiciously calculated: the readiness of these systems arrived in due time to respectively slow down the natural depletion of the reservoirs and improve the wells eruptivity and stability of the flowlines. Our capacity to re-invent ourselves and leave behind individual priorities conducted to a collective success captured in the outstanding production levels since early days of field life.

In a deepwater environment, production fluid conditions have to satisfy complex requirements to flow smoothly to the production facilities on the FPSO. Flow assurance specialists work at turning these constraints into operating guidelines. This allows to close the gap between reservoir conditions, optimized design of the subsea network, topsides processing capabilities and operability requirements. In the context of Kaombo, offshore Angola (Block 32), the wide range of reservoir conditions and fluids plus the extreme specificities of the subsea network called for an innovative approach with the following objectives: Empower the operator with a visual decision tool for normal and unplanned operations of the subsea systemPromote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfallsAllow a design robust enough to tackle geosciences uncertaintiesOptimize subsea design margins This new approach, the "Visual Operating Envelopes", aims at explicitly and visually defining the operating limitations of the subsea production loops in a multi-parameters environment: A multi-dimensions map, function of the six main parameters (basically liquid and gas-lift flowrates, water and gas contents, reservoirs pressure and temperature) influencing multiphase flow into pipeline is hence created to evaluate the six main operating constraints (thermal and hydraulic turndown rates, wells eruptivity, maximum flowrates) for the full range of Kaombo fields. This "operating envelope" tool can then define the minimum and maximum recommended flowrates for different operating conditions based on the following safe criteria: Arrival temperature above the Wax Appearance TemperatureNo hydrates risk during preservationNo severe slugging effectProduction below the flowline design flowrateVelocity below the erosional velocity In addition, the optimized gas lift flowrate is directly accessible, and the pressure available at every wellhead is compared to the backpressure associated to the operating point to assess the eruptivity of the wells. By having previously defined an overall operating envelope, it is extremely easy to evaluate quickly the impact of new operating conditions (due to degraded operating conditions, changes in reservoir parameters, modifications in the drilling and wells startup sequence), which makes this new approach very powerful and versatile. It also contributes to the definition of the production forecast during operation phase integrating reservoir depletion and available gas lift rate. Instead of relying on specific simulations for a limited number of cases, this innovative method defines a new approach where operating parameters are evaluated from the start, and boundaries are clearly identified, thus allowing to build a sound production profile for an extensive range of operating conditions. By doing so, system knowledge is improved, bottleneck conditions are anticipated, operators, flow assurance and geoscience teams are able to tightly collaborate and take smarter decisions together, resulting in more production. Eventually the method applied to a multiphase pipeline is actually transposable to every problem involving multi-dimensional inputs with combined constraints.