bluuebunny/crossref_metadata_2025_split huggingface dataset:
Life Cycle Water Management in Oil Production- The Good, The Bad and The Ugly
Authors: Ayeni Olukayode , Ayeni Olumide , Olatope Victor 
Published: October 2018

Abstract
There are quantum literatures, technical papers, etc on water management in the oil and gas industry. It is a very wide issue and with significant interest due to cost and environmental implications. The focus of this paper is water management in relation to oil production with the purpose of given the industry professional an all-round understanding of life cycle water management. Since by nature the oil is layered above water and the most common reservoirs drive mechanism is underlying aquifer (water), water production is therefore inherent in exploitation of oil. The impact of water in oil production could be good, bad or even ugly. This paper will discuss the various water management techniques from the drilling phase, through completion, production, transportation and treatment at processing facilities. Though basic, this is substantially fundamental. An improper management during any of the phases could prove very costly down the road to the promised developed ultimate recovery for a well completion and even overall recovery from the reservoir.
With water production, comes the associated cost of water processing and disposal. It is the view in this paper, that practices and technology should be deployed to delay and minimise water production where appropriate. In today's lower oil prices for longer world, the industry must always strive to reduce their UOC (Unit Operating Costs) to remain profitable and competitive. There are published estimates of water handling costs being as high as 50 cents per barrel of water produced. Reduction in this cost will surely impact the operating company bottom-line.
Though there are extensive literature that addresses specific challenges with water management in discrete phases of operation, this paper will attempt to provide a life cycle view, hence its uniqueness. It also highlights practical solutions that are tried and tested.
Reduction of Operating Cost Through Pipeline Flow Network Optimization
Authors: Onwuemene Onyeka Chiazor , Happiness Deele , Fadayomi Lanre , Okwudiafor Paul , Jabar Sheriff 
Published: October 2018

Abstract
Optimized flow assurance was achieved in an offshore Well Head Platform (WHP) via the use of a Surface Pipeline Network Modelling Tool. The WHP has 15 flowing wells with a flexibility of diverting the wells into either a 14" or 10" departing pipeline for processing on two production facilities. Because of high departing pressures on both pipelines, Drag Reducing Agent (DRA) injection was continuously introduced at an increased production operating cost to manage backpressures that impaired well deliverability.
The approach is based on simulating various Well flow configurations via the 2 production pipelines with the aim of reducing DRA injection to the barest minimum or zero from an injection rate of 5 gal/hr. Test results (GOR, Liquid rate, solution gas, BS&W, API gravity etc.) of all affected wells were utilised as input parameters during the simulation exercise. Various flow configurations were arrived at as DRA injection rate was steadily reduced from 5 gal/hr – 2gal/hr over a 6-month period. DRA injection rate of 0gal/hr was achieved after 1 year.
The developed Surface network model served as a guide in the process of eliminating the need for DRA injection. DRA reduces the turbulence in pipelines to allow a much efficient flow. This in turn aids well productivity by reducing back pressure on flowing wells. To assure the use-ability of the simulation model, it was validated by using it to match the flow characteristics of a different production network in the field using well test records and pipeline properties (roughness, length, diameter, et al.).
In conclusion, the Surface Pipeline Network Modelling Tool presented a technical basis for making an important operational and cost-effective decision which persists till today. A cost savings of ~$1.4MM/year in 2016 and subsequently ~$3MM/yr as best multi-phase Well flow configuration in the 2 pipeline systems was achieved.
The importance of this optimization is the need to fully exhaust the opportunities that software tools present in critical decision-making processes which could aid cost savings and solve knotty operational & HSE issues when robustly deployed
Simple Upscaling of Oil-Water Relative-Permeability Models
Authors: Eyitayo Stella I. , Lawal Kazeem A. , Ukaonu Cyril , Ovuru Mathilda I. , Anyadike Emeka , Sanyaolu Adeniyi A. , Olusoji Mojisola O. , Olushoga Elizabeth O. , Odubanjo Teleola O. , Matemilola Saka 
Published: October 2018

Abstract
A good description of relative permeabilities (relperms) is crucial to predict the performance of petroleum reservoirs. They are important input for evaluating fluid flow, and establishing the most suitable strategies for reservoir development and management. A poor relperm description is a potential threat to business decisions.
The applicability of a relperm dataset is highly sensitive to the scale at which it was acquired. For example, while special-core analysis (SCAL) data, which are often obtained from laboratory experiments may be adequate for core-scale simulation studies, they often fail to provide reliable description of fluid flow at the field scale. Although several upscaling techniques are available, they vary in their complexity and reliability. One area of improvement is to simplify the upscaling process.
Extending and improving the approach introduced by Alpak et al. (2010), this paper uses the idea of global connectivity factor and a linear scaling algorithm to develop a simple technique to upscale oil-water relperms. Compared to Alpak et al. (2010), whose work was limited to two parameters, the new technique includes mathematical functions to extrapolate five of the Corey parameters (exponents and endpoints) from SCAL to their respective field-scale equivalents.
With some oil-water SCAL datasets from three plugs in a Niger-Delta oil reservoir, the practical applicability of the proposed workflow is demonstrated. In addition, this paper covers the following areas: (i) upscaling individual SCAL plugs to preserve field heterogeneities; (ii) generating an upscaled model that aggregates all the SCAL plugs as an approximate homogeneous system; and (iii) constructing the full range of upscaled relperm models that reflect uncertainties for realistic reservoir simulations.
Economic Decision Making and Risk Analysis for Water and Gas Shut-Off Application
Authors: Egba Amba Ndoma , Ajienka Joseph A. , Iledare Omowumi O. 
Published: October 2018

Abstract
The decision to carry out a water or gas shut-off treatment in an oil well, is of concern to the petroleum engineer. The engineer must choose an explicit course of action with the information at his disposal. This decision however, has consequences that cannot be predicted with certainty. Water or gas shut-off treatments don't turn out the way we plan, because the outcome could be a success or a failure.
Traditional economic method of evaluating water and gas shut-off decisions typically involved cash flow considerations, such as net present value, which combine single point estimates to predict a single output. This method is deterministic, ignores the quantitative consideration of risk and uncertainty as one could be conservative with some estimates while being optimistic with others. The combined errors in this approach frequently lead to results that are significantly different from reality. Thus, a technique that will overtly include uncertainty in our estimates to generate results with all probable outcomes will aid the engineer in making an informed choice.
In this paper, the expected value economic concept is used for the mutually exclusive events of water and gas shut-off treatments. Through expected value and standard deviation of a random variable, Monte Carlo simulation and decision tree analysis, incorporating uncertainty in oil price, production forecast and operating expenses are used to evaluate the expected return and risk associated water and gas shut-off opportunities. This approach minimizes the chances of failure and provides useful insights for water and gas shut-off economic decision making.
Cross Functional Collaboration Resuscitates Idle Capacity in Etim Field
Authors: Akah Chikeluba I. , Abe Gbenga , Aina Bamidele , Oluchukwu Banye , Anumnu Emeka , Mkpasi Ernest 
Published: October 2018

Abstract
This paper details the importance of cross functional collaboration in the oil & gas industry. A team consisting of Geoscience, Reservoir, Subsurface and Drilling Engineering was tasked with maximizing asset value in the Mobil Producing Nigeria operated Etim field in southeastern Nigeria. Their collective effort resulted in identifying an idle wellbore to resuscitate shut in production and maximize hydrocarbon recovery at minimal cost. The expected initial uplift from the project is 8.4 kBD, and esitimated ultimate recoverable (EUR) is 9.9 MBO.
The Etim field is located in the Nigerian National Petroleum Corporation (NNPC) / Mobil Producing Nigeria (MPN) Joint Venture (JV) acreage in OML 67, south of the Qua Ibo Terminal (QIT). The field was discovered in 1968 and commenced production in 1972. There are 3 reservoirs in the field - the undeveloped Benin D1, Biafra Deltaic (BQI) and Intra Qua Iboe (IQI) Deepwater channel sands.
The BQI reservoir has a dominant water drive, while the IQI is solution gas drive. Post-production data shows flattened pressures in the BQI and significant pressure depletion in the IQI. An estimated 33% of the wells in the IQI are currently shut in on Low Well Head Pressures (LWHP) due to depleted reservoir pressures. Attempts to open wells after prolonged idle periods have proven unsuccessful.
The unavailability of pressure maintenance in the Etim field led the asset team to look for cost effective methods to revive the field's production. An idle oil producer in the BQI was identified for conversion to a Gas Source Well (GSW). The gas source well will provide high pressure gas for gas lifting and reviving production from the 6 shut in oil producers.
Invaluable Role of Pressure Data in Reservoir Management: A Deepwater Field Experience
Authors: Adegboye Phillip , Bodunrin Abiodun , Okpani Olu , Atuanya Chukwuma 
Published: October 2018

Abstract
This paper reviews and shares lessons on the critical role of subsurface pressure data in the successful management of Agbami Field. Agbami is a Chevron operated deepwater asset located in 4,800 ft of water with a combination of water and gas injection development strategy. Production commenced in 2008 and has remained plateau at over 240 MBOPD. The field hosts intelligent well completions with capability of real time pressure data acquisition. In addition to this suite of pressure data from downhole gauges, wireline and LWD tools have been deployed to acquire valuable pressure data in the field.
Several applications of reservoir pressure data in Agbami Field are shared in this paper. First, pressure data was used in establishing connectivity between a water injector and an oil producer in a rather poor seismic amplitude area. This led to significant savings from drilling another injector to support the 20,000 BOPD producer. Second, a reservoir originally interpreted as "virgin", which was later found to be depleted is described. This reservoir re-characterization resulted in over 20% increase in oil recovery. In another case, oil-water contact in a major reservoir was estimated using wireline pressure data, resulting in the booking of additional proved volumes.
One key lesson is to always integrate pressure data with other data in the field. This integration often improves the asset team's understanding of the reservoir. A best practice is to ensure that all pressure data is quality checked before use to avoid erroneous interpretation. The availability of subsurface pressure data from different tools, at different gauge depths and at different times, poses a common challenge: RM practitioners who utilize these data need to ensure proper correction is done before field application.
Optimal Well Placement in a Brown Field: Integrating Subsurface Data, Surface Constraints and Business Goals
Authors: Okereke Onyebuchi , Okpala Justin , Ajao Oyekunle , Salami Ibidapo , Etoh Maryjoy , Sotunde Oluwole , Nwaochei Francis , Okeke Genevieve 
Published: October 2018

Abstract
Well placement is often an arduous task because of the need to integrate varied information, from subsurface to surface; while trying to maximize business goals. Conducting this activity in a non-systematic manner can be frustrating to a team as well as reduce the chances of obtaining an optimal well placement and more so non-approval of execution proposal. This paper documents a systematic approach employed by the Field Z team in selecting the well locations of 4 – 8 wells scheduled for near term execution to ensure best value for all stakeholders.
Understanding of the subsurface information is the foundation of well placement. Identification of optimal subsurface location for maximum recovery was done using dynamic simulation. Being a brown field, available data from numerous producing reservoirs in the field were analyzed and used in representing some of the key factors affecting recovery. Upon determination of an appropriate subsurface location, we went ahead to highlight the various possible surface locations to check for slot availability.
Other considerations made in choosing the surface locations for each of the wells in this brown field "re-development" include: (1) jacket condition / cost of refurbishment, (2) drillability, (3) collision assessment, (4) impact of well path on recovery potential, (5) bottleneck analysis of production network, (6) impact of well path on completion installation, (7) Impact of well path on future well work and (8) well economics.
This paper puts forward a systematic approach ("Well Location Decision Matrix") to facilitate the decision-making process in selecting an optimal well location in a brown field; clearly articulating the values and trade-offs considered during the process. The ultimate value being the selection of optimal well location from reservoir management and economic points of view as well as obtaining all key stakeholders’ alignment/approvals for the project maturation.
A Geochemical Approach to Resolve Uncertainty in Quantifying Oil-Based-Mud OBM Contamination of Reservoir Fluids
Authors: Nwume Michael , Ekweozor C. M. , Ekun Oluseye 
Published: October 2018

Abstract
Oil-Based Mud (OBM) contaminated Pressure-Volume-Temperature (PVT) samples presents a strong challenge for accurate study of fluid properties, phase behavior and geochemical characterization of reservoir fluids. On-site analyses of OBM contamination in reservoir fluid samples with formation testers are usually performed with proprietary subsurface real-time fluid analyzers that utilize light absorption and tracer techniques.
In the laboratory, skimming and subtraction methods have traditionally been used to appropriately quantify level of contamination in PVT samples but the success of these two methods depends on the reservoir fluid type. The skimming method has been observed to yield unreliable results for biodegraded oils due to loss of some n-alkanes and isopreniod hydrocarbons in the oil. The accuracy of the substraction method however relies on the composition of the contaminated reservoir fluid and the mud filtrate/base oil analysed by Gas Chromatography. For high OBM contaminated and biodegraded samples, these two methods have shown to be unreliable for quantitative decontamination of oil samples.
In this paper, we present a geochemical approach developed for validating the results from traditional methods of quantifying OBM contamination in biodegraded and high OBM contaminated samples.
Tackling Watercut History Matching Challenges for Proximal Wells- A Niger Delta Case Study
Authors: Ogbuagu Frank , Tsakporhore Abraham 
Published: October 2018

Abstract
This paper reviews a history matching case study of a reservoir with two oil producers located proximally in the same reservoir, with a slight vertical offset. This proved challenging to match due to the significant difference in the water production trends. This study highlights the methodology taken during the history matching process to identify the key element(s) responsible for the marked difference in water cut trends. The objective of this paper is to share steps taken in identifying the variables responsible for the observed behavior and showcase the results of key tests on variables in the reservoir during the history matching process. Details of the investigative process undertaken to identify the defining variable/element impacting the water production performance will be shared with lessons learned from the process itemized.
The history match efforts revealed that the difference in water production signatures seen from both wells close to each other was because of the contrast in reservoir static properties which occur between the wells. This prompted a revisit of the seismic data for the region, which corroborated the updated reservoir understanding. Following these learnings, the history match project was completed and resulted in the optimal placement of a new development producer well. Initial production results from the new development well matches closely to the model forecasts, further validating the model parameters and stratigraphic inferences.
A key lesson learned from this project is that localized history matching difficulty is best tackled by first reviewing drilling and completion data for the area of interest, the initial test data and a revisit of the stratigraphic concept use in the earth modelling phase of the project. As a best practice, thorough investigation of stratigraphic concepts for the reservoir alongside analog reservoirs will help in a more accurate first-time description for the reservoir.
Innovative Cement Packer Deployment without the Associated Skin: A Niger Delta Case Study
Authors: Ogbuagu Frank , Tsakporhore Abraham 
Published: October 2018

AbstractThe use of cement packers to access behind-pipe hydrocarbon opportunities has opened up significant reserves without the attendant cost of a rig. A key challenge with this technique is the attendant high skin that results from the cement packer which significantly impacts initial production rates and recoverable reserves.The objective of this paper is to share technique and lessons from a case study in a mature field, offshore Niger Delta where an innovative technique was employed to place the cement packer above the perforation interval in the target reservoir. This eliminated the skin due to the cement packer, leading to significantly higher initial production rates when compared to analog workovers.The paper details operational procedure during execution. The lack of a local precedent in the deployment of this type of cement packer presented a key challenge. Perforating the target reservoir and string without impacting the second string in the wellbore was another challenge.The initial production rate from the case study was 2200 BOPD vs 800 BOPD or less from analog cement packer workovers. A key lesson learned is that this solution is best suited to wellbores with a single production string only or multiple strings wellbores in which there is no further production utility for the additional strings. The follow on best practice from this lesson is to fully evaluate the wellbore utility for any identified opportunity of this sort to ensure the deployment of this method does not impede the utility of the wellbore for future reservoir management operations.
Self-Lift and Gas-Lift Slug Mitigation Techniques Combined: A New Approach to Severe Slug Mitigation in Deepwater Scenario
Authors: Okereke Ndubuisi U. , Ogiriki Shadrach O. , Igbafe Anselm I. 
Published: October 2018

Abstract
In recent times, studies on slugging have focused on the development of new and optimal slug mitigation techniques. This study focused on investigating a new proposed severe slug mitigation technique which involves combining self-lift and gas-lift. The self-lift slug mitigation technique is a unique approach that involves in-situ gas being tapped-off via a by-pass pipe along a pipeline upstream of a riser. The in-situ gas is then re-injected into the riser column via an injection point on the riser, to break liquid slugs within the riser column and mitigate severe slugging. This study adopted a methodology which involved validating the field data by comparing field pressure data with OLGA simulation based on input data from the field. The field case involved a deepwater oil field, consisting of well X1 and well X2 comingled along a 2712m pipeline section and a 1513m riser section. The pipeline-riser system in consideration in the case-study experienced hydrodynamic slugging, during the early life of the field; when the two wells comingled on the pipeline-riser system were operating at 3000 bbl/d. The 3000 bbl/d scenario (well X1 – 8.745 kg/s and well X2 – 25.13 kg/s) was initially modelled via OLGA. Furthermore, the 3000 bbl/d scenario was modified by moderating the flow rates at well X1 to 3.25 kg/s and well X2 to 12.13 kg/s until severe slugging scenario was observed, which was verified via pressure and holdup trend plots. Self-lift technique alone was able to moderate holdup within the riser column, however pressure trend at the riser column was observed to be over 20 bara (290.075 psi) which is the design pressure for the inlets of the separator. Further analysis of results obtained via the combination of self-lift and gas-lift at 2 inches by-pass diameter and 8kg/s gas-lift showed that pressure at the riser column was stabilized to approximately 20 bara (290.075 psi). This study showed that a by-pass internal diameter to pipeline-riser internal diameter ratio of (1 : 2) or less is crucial to the effectiveness of self-lift and gas-lift slug mitigation techniques combined. The new approach proposed in this study also has the potential of moderating the high compressive cost associated with gas-lift in deepwater scenario.
Effect of Fluid Compressibility on Toughness-Dominated Hydraulic Fractures With Leakoff
Authors: Wang Di , Chen Mian , Jin Yan , Bunger Andrew. P. 
Published: October 2018

Summary
Hydraulic fracturing using supercritical carbon dioxide (CO2) has a recognized potential to grow in importance for unconventional oil and gas reservoirs. It is characterized by higher compressibility than traditional liquid-phase hydraulic-fracturing fluids. Motivated by the larger compressibility of supercritical CO2, this paper considers the problem of a hydraulic fracture in which a compressible fluid is injected at a constant rate to drive a hydraulic fracture in a permeable and brittle rock. The two cases of a plane-strain fracture and a penny-shaped fracture are considered. It is shown that for many practical cases, the formation has a large enough fracture toughness that the propagation is in a regime for which the pressure inside the hydraulic fracture can be treated as spatially uniform (“toughness dominated”). Both numerical simulations and analytical solutions for the relevant limiting regimes show that fluid compressibility affects fracture shape only at the very beginning period, which corresponds to the storage regime, and has little effect on fracture growth in the leakoff regime. Overall, because the transition from the storage regime to the leakoff regime is expected to often take place in a short time after the fracture starts propagating, the influence of compressibility in the storage regime is very brief and can be quickly ignored. Therefore, even relatively sizable fluid compressibility has almost no effect on fracture growth in the toughness-dominated regime when leakoff is taken into account.