A quick evaluation of reserves for new opportunities (e.g. perforation extension and other work over types) in reservoirs with distinct geological units and features is possible using a multi tank MBAL option. This saves time while still having results closely matching more detailed simulation models besides reservoir management due to subsurface uncertainties. In cases where a reservoir is naturally separated into units with the aquifer as the only common communication base or where there are constricting saddles which in production time allows preferential sweeping of the reservoir posits the possibility of separate tanks. Multi-tank MBAL has been used in this scenario to generate a production forecast for a work over opportunity in Reservoirs A, B & C. This methodology transmits the segregated accumulations of the reservoirs into tank sectors and connects them using transmissibility value to a common aquifer leg in a multidisciplinary approach. Resultant model is history matched and contacts calibrated prior to prediction especially when present contact information exists. The methodology as opposed to a single tank MBAL model gives better calibration of contact movement and forecast of the future and existing opportunities, thus giving credence to more robust reservoir management plan and resource volume estimation for the work over project. The MBAL multi tank methodology is a handy improvement tool for brownfield production forecast within the Wells, Reservoir & Facility Management domain especially where no 3D dynamic models exist.

Maximum efficiency rate (MER) is the production rate above which the reservoir recovery (particularly around the well) is endangered thereby eroding lifecycle economic value. The current practice in the Niger Delta entails the application of the equilibrium concept which (in this case) requires the use of a combined graph of tubing head pressure (THP) and choke size against the production rate where the point of intersection between the plots is considered the stable equilibrium and the corresponding rate, the MER. However, experience has overtime shown that adjustment of the scale of the vertical axis would yield different values of MER; and thus can be adjudged as physically inconsistent. To address this inconsistency, a robust methodology that will be acceptable to both the regulators and partners is being proposed by first understanding and establishing the limitation of the current methodology and demonstrating same using the combined THP and choke size versus production rate plots on a single graph. Subsequently, the relationship between key elements of changing THP (due to varying choke sizes) and their attendant back-pressure effect at the sand face impacting on reservoir withdrawal at given physical well conditions was established and normalized (using first order derivative function) to capture possible variations in the tubing head and sandface pressures over any production period. The impact of choke size adjustment on the ‘changes’ in THP and production rate at a particular physical well condition was modeled and a combined plot of the ‘change’ in THP and production rate at varying choke sizes was then generated on a single graph. The result proves to be more physically consistent and can easily be replicated across the industry. This paper demonstrates the gap in current MER estimation methodology and proposes a new thinking and more effective approach; sharing the results of its application and value for both regulators and operators.

Engineering problems may be easy to solve when they are properly understood and straight forward. Often times, most oil and gas industry problems pose multifaceted reasoning challenges to the engineer and an array of possible answers only make the solution complex. Many projects have been stalled due to complexities they pose and others have suffered unending futile efforts trying to address the cause of problem. Sometimes there may appear to be several very likely causes deducible from analyses. However, there can only be one remote cause and the identification of that remote cause is the end result of the Solution-By-Elimination (SBE) approach; the solution consequently will be fit-for-purpose addressing the main cause of problem and adding value to SPDC business. The SBE is a systematic and sequential end-to-end process that considers careful observation of evidence, identification and enlistment of all possible/probable causes of a problem, analysing and narrowing down to the root cause. It is a stop-gap approach in successfully solving complex oil and gas problems. This paper presents the experiences gathered from solving observed production problems in selected SPDC fields, to provide basic guidance to identifying the root-cause of complex oil and gas industry problems using the Solution-By-Elimination (SBE) Approach. Illustrations from selected case studies in some SPDC fields: Case 1 is a complicated case of severe (over 100ft of sand) sand build-up in a dump-flood type injection well and the result of analysis showed that the sand was from the target (injected) zone caused by a late time re-perforation event whereas Case 2 is a case of repeated flowline approach sectional failure and the root-cause of the failure was adjudged to be Cavitation Erosion.

No horizontal gas well has been drilled in the Niger Delta since the inception of the technology and its first application in the region. The argument has been that the present vertical well technology, unlike oil, is adequate for gas production considering the relatively favourable petrophysical properties (e.g. permeability) and the usually significant pay thickness in the region. As a result, no evaluation of possible application of the horizontal well technology in gas production has been considered in the region. However, there are several pockets of gas resources trapped in highly heterogeneous reservoirs of less than 20ft within the region which pose deliverability challenge to the use of vertical wells in terms of drawdown and flow assurance. For a quick evaluation of the possible impact of horizontal technology on gas well deliverability in the Niger Delta, the effective wellbore radius concept was applied. This concept can be used for practical comparison in reservoirs and/or fields where no horizontal well has been drilled; particularly for small pay thicknesses. As a result, a comparative horizontal inflow model for pseudo-steady state radial flow was developed and validated using field data. It was observed that for thin anisotropic reservoirs, horizontal well performance is at least better than vertical well as much as the following conditions are satisfied: (1) h/L=0.1 for all the sensitized range of kh/kv, (2) h/L=0.2 for kh/kv ≤ 35, (3) h/L=0.3 for kh/kv ≤10, (4) h/L=0.4 for kh/kv ≤5 and (5) h/L=0.5 for kh/kv =2. Above the scaled aspect ratio boundaries, the deliverability ratio drops below one. Though the horizontal well deliverability is higher the impact of turbulence is seen to be in the range of 0.98 – 1.06 depending on the scaled aspect ratio; and the effect of reservoir anisotropy is between 2 – 80% for these thin reservoirs across typical ranges (200 ≥ kh/kv ≥ 2) seen in the Niger Delta. This paper presents the comparative model and its quick evaluation results with examples after due testing; considering the impact of non-Darcy turbulence, scaled aspect ratio and reservoir anisotropy.

Several multiphase models exist for predicting pressure drops in vertical, inclined and horizontal wells. Most of these models made efforts to unravel the underlying physics of multiphase fluid flow for both mechanistic and analytical models with ranges of applicability. However, these developed models have their specific limitations or ranges of applicability in terms of pressures, rates, basic sediments and water (BSW), choke sizes, fluid ratios, etc thus there is no one model that is universally acclaimed best. Data from fifteen (15) wells were obtained from a Nigeria field and multivariate linear regression was fitted into the data resulting in a good fit particularly for high production rates/wells. The method of least squares was adopted which involve setting up a set of normal equations, solving them by Gaussian elimination technique and fitting the data into the normal equations. The solution of the primary matrix was obtained through the use of MATLAB software which gave point estimates of the regression parameters leading to the development of multivariate linear regression model. The Bootstrapping method of statistical inference was also used to estimate the confidence interval of these regression parameters, while the Durbin-Watson test statistic was used to test model adequacy. The results of the model compared favourably with existing models within considered range of applicability. This paper therefore aims to address the challenges of field based multiphase fluid flow model for operational ease using a set of over one thousand production data sets of about forty (40) years of production taken from a renowned field in the Niger Delta. More specifically, our investigations show that taking the infimum (i.e. lower bound) of the parametric bandwidths of the gas rate, average bean size and the model correction factor, b0 the model predictive capability is drastically improved for low to medium rates.