bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reducing Uncertainties in Mud-Gas Data Acquisition While Drilling-Offshore Depo-Belt, Niger Delta
Authors: Onyeji J. A. , Ekanem A. U. , Owoyemi A. , Adole S. A. , Ekun O. A. , Nwankwo C. N. 
Published: October 2018

Abstract
Over the years, the acquisition of gas in mud is crucial to the exploration and production (E&P) industry for the evaluation of hydrocarbons presence in the geological formation, and for monitoring of drilling operations. The mudloging technique involves continuous gas extraction and analysis from a circulating drilling fluid for quantity and composition using surface gas trap, gas lines and gas analyzer. This paper presents major uncertainties that associated with gas acquisition during drilling, sources of the uncertainties, and the way forward to acquire highly accurate gas-in-mud data.
During the process of acquiring gas-in-mud data, some uncertainties have been observed which can adversely impact real-time decision making as well as cascading effect on the geological models built with this data. In some of the recent wells drilled in offshore depo-belt of Niger delta the following uncertainties were observed; (1) Shift-in-the gas analysis window- Methane (C1) and heavy gas components (C4 and C5) were present in the absence of some light gas components (C2 and C3), (2) Misaligned gas data- gas values acquired misaligned with the resistivity readings of the reservoir being drilled, and (3) Gas in mud (volume and component) underestimation across the reservoirs; Lao-2 reservoir up to 35 units (0.7%) total gas, and gas composition- C1 to C3, and Mao-1 reservoir up to 27 units (0.54%) total gas, and gas composition- C1 to C2 were recoreded at well 43H drilled. This study showed that these uncertainties could result from a drop-in sample pressure or moisture in the gas line, real-time transmission of gas in mud data in bit depth instead of lagged depth and poor calibrations of gas analyzer. The issues then, are how to minimize these uncertainties to obtain accurate gas in mud that truly represent the reservoir being drilled. A systematic approach was deployed to minimize the abovementioned uncertainties. The methodology adopted significantly improved the data acquired in the new well drilled in the field. Highly accurate gas in mud data were obtained in the same reservoirs at the new well (44H) across Lao-2 reservoir: 190 units (3.8%) total gas, and gas composition- C1 to C4, and Mao-1 reservoir: 430 units (8,6%) total gas, and gas composition- C1 to C5. The new well is about 200m away from well 43H. The new well 44H was drilled under same drilling conditions as well 43H; same drilling fluid properties, rheology, mud weight, bottom hole assembly configuration and within the same fault block. Thus, we recommend; constant inspection of surface gas trap and gas agitator, periodic blow back of gas lines, multiple points gas calibrations, detailed gas analyzer calibrations for both total hydrocarbon analyzer and gas chromatograph prior to drilling operations, Maximum of five percent standard error margin, and periodic inspection of gas analyzer filament.
Successful High-Angle Through-Tubing Cement Packer Deployment and Reperforation Using Coiled Tubing: Offshore Niger Delta
Authors: Osaronwaji Emmanuel , Nnajiofor Okwouma , Chemmarikattil Rohan , Talabi Olufemi , Onuh Haruna , Onobrakpor Ochuko , Omodu Orji 
Published: October 2018

Abstract
Most economically feasible production optimization plans for brown fields include deploying rigless technologies for accessing reserves originally considered marginal and were, therefore, bypassed during the early stages of field development. Because these bypassed reserves were not considered significant, most of the wells were completed leaving behind potentials above the production packer that were not considered economically recoverable. Within the Niger Delta mature fields, a greater percentage of the remaining recoverable reserves have been overlooked as bypassed hydrocarbon volumes. Redeveloping the bypassed pay in highly deviated high-angle wells presents challenges, and accessing them usually necessitates pulling the tubing through a major rig workover. Such operations use far greater resources than rigless well interventions offshore and can often consume unaccounted for time in milling.
Rigless through-tubing cement packer technology and reperforations have been deployed to access marginal/bypassed pay in mature fields. Cement packers typically provide a means of zonal isolation of the last reserves in an existing wellbore above the production packer. The success of these operations has historically been low in highly deviated wells primarily because of poor cement bonding in the annulus between the tubing and production casing and issues with pulling the coiled tubing (CT) out of hole while maintaining differential pressure between the wellhead and casing head pressures.
This paper presents the successful deployment of through-tubing cement packer rigless reperforation without sand exclusion for accessing bypassed hydrocarbons in high-angle (72 to 80°) deviated wells through CT, offshore Niger Delta. This paper reviews design considerations and precautions for placing the high-angle cement packer through CT as well as production results. Post-operation shut-in tubing and casing pressure, quantity of cement slurry pumped, and extended flow testing have proven the success of the design and procedure implemented.
Annular Packer Seal Remediation through the SS in a Dual Completion Using Coiled Tubing: Onshore Niger Delta
Authors: Atakele Longfellow O. , Anim Osadebe J. , Airhis Osahon N. , Omodu Orji , Onobrakpor Ochuko , Onuh Haruna , Udensi Anthonia 
Published: October 2018

Abstract
A dual string well in the Northern Niger Delta was diagnosed with a well integrity problem resulting from mechanical setting failure of the long string (LS) packer during initial completion. The well was designed to produce the deeper condensate reservoir through the LS and shallower black oil through the short string (SS). The packer failure created wellbore communication across the two strings, which resulted in the shutting in of the well because of a sudden increase in water cut. The communication was evident in the condensate production from both strings, suggesting production loss from the deeper condensate reservoir to the shallower black oil reservoir.
A cost effective solution without recompletion was necessary to isolate the leak across the packer and eliminate the cross string communication. The initial proposal was to perform a rigless through-tubing operation that would involve setting plugs in the LS and perforating the LS to enable setting of the cement plug on the failed packer. The downside to this approach is difficulty milling the cement and plugs in the tubing after the operation, as well as the complexity of the entire operation.
This paper presents a novel solution to the problem by deploying coiled tubing (CT) with optimized cement slurry through the SS. Six CT runs were made, exiting the SS 1,365 ft in each run and thereby eliminating the cost of plugs and perforation in the LS. The pump and pull method was used to spot the cement plug. The packer leak was isolated, and black oil production was established through the SS. Postoperation production proved the design a success. The procedure was implemented resulting in more than a 60% increase in production from both strings, and water cut was reduced to less than 1%. A cost reduction of more than 90% was realized compared to a workover option.
Economic Viability of Infil Drilling Program for Marginal Oil Field Development: A Case Study of Sango Field in Nigeria
Authors: Dagogo Opiribo , Iledare Wumi , Humphrey Oruwari 
Published: October 2018

Abstract
Infill drilling can be defined as the drilling of an additional well in a field that has already completed primary production; it is a rate acceleration investment that increases cash flow schedule similar to installing large volume lift equipment. The study evaluates the economic viability of applying infill drilling program to marginal oil field development in Nigeria using Sango field as a case study. This study was carried out to evaluate the economic viability of infill drilling program for marginal oil field development in Nigeria using Sango Field as case study. The study employs the dynamic reservoir simulation using Eclipse 100 Black oil simulation software to quantify the infill potential of the remaining reserves and based on the results of the incremental recovery from the simulation, one additional well was proposed for drilling. Economic analysis was carried out on the drilling prospects using cash flow model to evaluate the profitability. Stochastic evaluation of the deterministic single values was conducted using Oracle Crystal Ball software to quantify the risk and inherent uncertainties. This was followed by performing a sensitivity analysis to determine the effect of key variables on the profitability of the venture. The result of the analysis showed that the Long Term Activities (combined) scenario recorded the highest incremental recovery of 2.45MMSTB. The project Net Present Value for the drilling option is $1.0 Million at a discount rate of 11% while the internal Rate of Return is 12%, the profitability index is 1.1 and Payout Period of 4.26 years. Probabilistic analysis gave better confident level that encourages investment while the sensitivity analysis revealed tax rate, oil price and initial investment as key parameters affecting the profitability of the venture. The long time activities that gave an incremental of 2,45MMSTB was proposed for the Sango field which involves the production of the fields with both old existing well and the newly drilled well. It is recommended that there is the need for less demanding and cost effective method to quantify infill potential in marginal oil field as against the detailed integrated reservoir study that is time consuming and expensive for operations of marginal fields. The significance of the study is that it will provide valued information for marginal field operators that will guide investment decision making.
Upstream Mergers and Acquisition Deal Valuation - A Global and Africa Outlook with Perspectives for Nigeria
Authors: Gbakon Kaase , Abiola Olalekan 
Published: October 2018

Abstract
The objective of this paper is cast as a historical narrative of the global oil and gas upstream M&A activity as revealed by such metrics as deal count, deal value, quantum of proved reserves up for M&A and the accompanying segregation by region, deal category, and terrain location of deal asset. Furthermore, the study contemplates the question on the character of the next cycle of M&A activities within the Nigerian upstream space. Additionally, the paper explores the possibility of adjusting valuation methodologies based on the result obtained.
For this assessment, the paper relies on a database of M&A transactions which contains 6,444 deals from 2001 to 2017 (Sept.). The database is queried for deals for which there is a reported deal value thus allowing M&A deal activity to be tracked, trended, and correlated. This provides a critical look back on the dynamics of the M&A market with a view to offer an outlook of the M&A deal space. Approximately 77% of the parent database size contain transactions with deal value recorded. Both the annual M&A deal count, and the deal value closely track the trend for oil price with correlation coefficients of 76.34% and 65.84% respectively. Over seventeen years from 2001, an estimated $2.22Trillion (RT2016) of M&A value has been transacted, 56% of which has been due to transactions primarily in North America, 17% in Russia and the Caspian, 8% in Europe and 5% in Africa.
Segregating deal value by asset location reveals a constrast between deepwater and onshore. In terms of value, DEEPWATER acquisitions totaled $230Billion (RT2016) globally over the 17year period, which is only 15% that of ONSHORE acquisitions while the aggregate unit deal value for DEEPWATER at $19.50/BOE (RT2016) is more than 2–times that of ONSHORE acquisitions. Within the Africa M&A deal space, data shows that deal value is driven primarily by oil price and proved Serve Size (in MMBOE), with the greater impact due to the Proved Reserve size in the target deal where a 10% change each in Reserve size and Oil Price results in 10.74% and 8.53% change in deal value respectively. To further the study, a closer look at the Nigeria M&A space was undertaken.
A New Approach to Maximum Efficiency Rate Estimation in the Niger Delta
Authors: Sukubo Ibianga , Obi Peter 
Published: October 2018

Abstract
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.
Unconventional Challenges and Solutions in Liner Cementing: A Case History from Nigeria
Authors: Adesanya Olukayode , Mofunlewi Samuel S. , Ighodaro Osaze , Fagbemi Timothy , Ibrahim Timothy , Timibitei Fred 
Published: October 2018

Abstract
Incorporation of innovative well delivery practices has been on an increase over the years and there are several phases of operational engagement that aid in achieving the required well objectives. Primary cementing is a key phase of wellbore construction as it secures the well's structural integrity, also serving as a barrier to keep formation fluids at bay.
There are several challenges associated with carrying out wellbore zonal isolation for conventional primary cementing of casings. However, a unique level of attention is required during the design and execution stages of liner cementing. The slurry design requires careful formulation to desired specifications while ensuring it is easily deployed and placed in the liner annulus. Additionally, there are several downhole tool constraints that come with liner cementing related to the complexity of the liner hanger technology. Various tool configurations are available to make up the liner hanger system. A typical system will include casing joints and the liner top packer Run in Hole (RIH) to the designed depth.
The process of cementing a liner comes with unique procedures. From the design phase to the execution, special consideration of all downhole fluids to ensure flawless cement placement while preventing intermixing and contamination is critical. The complex nature of the liner hanger system requires thorough analysis in order to provide lasting solution to effectively perform cementing placement and zonal isolation throughout the liner casing, hanger assembly and liner top.
One major challenge is the risk of possible contamination of the cement slurry with un-displaced mud in certain sections of the liner hanger system. The effects of mud/cement contamination can lead to grievous consequences and is fully analyzed in this paper. A high profile cementing operation carried out in the southern part of Nigeria is used as a case study on how the liner hanger configuration and drilling fluids design can positively influence the successful deployment and effective zonal isolation of the liner. Emphasis on several procedural considerations that are often overlooked while designing the drilling fluids properties and characteristics for liner hanger cementing will be presented with recommendations on tracking and with improvements in future operations noted.
Quantifying the Impact of Water and Gas on Oil Production
Authors: Egba Amba Ndoma , Ajienka Joseph A. , Iledare Omowumi O. 
Published: October 2018

Abstract
The impact of water, gas or a combination of both in oil production is an important aspect of petroleum engineering operations. Some water or gas production could contribute to oil production increase while in some cases such production could be less beneficial. Analytical techniques to quantify the impact are still lacking because the solution to multiphase flow problems in heterogeneous reservoirs is complex. Material balance procedures are deterministic and do not take into account the heterogeneity in reservoir behavior. Simulation techniques could be used but these are very expensive and require, a lot of time and information, which may not be handy.
Using time series data analytics techniques, a method has been developed that is used to quantify the impact water, gas or a combination of both will have on oil production, in the short run and in the long run. This technique is also used to determine whether water, gas or a combination of both is a significant causal factor in oil recovery or not. The approach is innovative as it will help to isolate desirable and undesirable water or gas production before applying expensive diagnostics.
This new Method has been tested with field data and could be a useful tool for reservoir and production engineers.
Application of Fluid Contact Match in Material Balance Study in a Water Injection Reservoir to Estimate STOOIP and Initial Reservoir Contacts
Authors: Obot Nsitie , Eme Vincent 
Published: October 2018

Abstract
Original hydrocarbon in-place and aquifer influx for a reservoir can be estimated using the classical Material Balance Equation (F = N*Et + We). Being a single equation with many unknowns, this makes the solution to the equation non-unique with a wide range of OHCIP estimates. Including fluid contact tracking helps to constrain the range of OHCIP and better define the initial conditions of the reservoir.
The objective of the material balance study was to estimate the STOOIP and initial reservoir fluid contacts for two waterflooded reservoirs. The volumetric estimates of STOOIP for the proved area (defined by the HKO and ODT) gave very optimistic recovery factors to date. This paper will discuss the methodology used for estimating the initial reservoir condition by using fluid contacts tracking to constrain the material balance equation for production history match.
Reservoir A2 was discovered with no initial fluid contacts seen in the reservoir prior to the onset of production. Water injection started in the reservoir after fourteen years of production. Oil RF to date from the reservoir is over 61% of the volumetric STOOIP estimate (265 MMSTBO) using the first fluid contacts seen in the reservoir post-production.
Reservoir A3 was discovered with an OOWC and HKO with volumetric STOOIP estimate of 295 MMSTBO. Initial water injection started in the reservoir after fourteen years of production. Oil RF to date from the reservoir is 71%.
Integrating fluid contacts tracking in the material balance study helped constrain the STOOIP estimates and give more realistic values (45 – 50% for reservoir A2 and 60 – 65% for A3). The STOOIP and initial contact estimates from this study were used as basis for comparison with the dynamic simulation study and the results were within 5%. These case studies show that applying fluid contact matching in material balance can help with better estimates of STOOIP and initial reservoir fluid contacts.
This is of great importance to the optimum development of these reservoirs and has led to the identification of new drill opportunities in each reservoir.
Phytoremediation of Petroleum Hydrocarbons in Polluted Waters Using Pistia Stratiotes: Gaps and Future Perspective
Authors: Ekperusi Abraham O. , Sikoki Francis D. , Nwachukwu Eunice O. 
Published: October 2018

Abstract
Environmental pollution in the oil and gas industry is the unintended but inevitable consequences of oil and gas exploration and production. Over the years, different strategies have been implemented for the remediation of oil-polluted waters. The increasing call for the use of ecologically based solutions for remediation have intensified the quest for engineers, researchers and scientists to find pragmatic solutions from the natural world. Among the several biological application for the remediation of petroleum-polluted environment, aquatic macrophytes are becoming a promising and ecological based solution for the removal of hydrocarbons pollutants in water. Pistia stratiotes, - a monotypic genus in the family Araceae, is a floating aquatic macrophyte with extensive application in the phytoremediation of organic pollutants, heavy metals and sparingly in agrochemicals, pharmaceuticals and personal care products, nanomaterials, radioactive materials and petroleum hydrocarbons in wastewater effluents and aquatic environment. The dearth of studies on the application of water lettuce for the remediation of petroleum hydrocarbons and oilfield chemicals creates a gap in the potentials of the plant for long and short-term assessment of hydrocarbon uptake, removal and degradation in contaminated waters. There is need for laboratory and field trials on the application of P. stratiotes to remediate hydrocarbons and other related pollutants in oil and gas exploration to elucidate the effectiveness and efficiency of the plant as a sound ecological base approach for sustainable remediation of hydrocarbons in a polluted environment.
Extended-Reach Drilling To Maximize Recovery From a Mature Asset: A Case Study
Authors: Muecke N.. , Wroth A.. , Zharkeshov S.. , Anton R.. , McCourt I.. , Armstrong N.. 
Published: October 2018

Summary
This paper shows how the implementation of a continuous-improvement process, in combination with precampaign-engineering and planning-optimization efforts, allowed the operator to expand the existing drilling-and-completion envelope in a mature offshore field. This provided a cost-effective means to access the remaining attic and undrained oil in a very shallow reservoir. Application of new technology, extended-reach-drilling (ERD) practices, complex completions, detailed engineering, good-quality real-time data, and execution support at the rigsite drove the evolution of well designs for the operator during the last 8 years, enabling the life of this mature asset to be extended. This paper highlights the evolutionary process applied to enable economic in-field development, with an emphasis on relevant transferable learnings that might be applicable to other complex ERD-well projects within the industry.