bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Evaluation of Improved Oil Recovery Methods in a Libyan Oilfield
Authors: Ifelebuegu Augustine O. , Zydan Zydan H.
Published: February 2021

Intisar A oil field is a Libyan field located in Concession 103 and has been in production since 1968. In this paper, we report the field evaluation results of the various productions enhancement techniques and initiatives applied for incremental oil production. The impact of improved recovery by various waterflood optimisation processes including infill well drilling, installations of ESPs, current well re-completion, and conversion wells were evaluated taking into consideration surface facility constraints. An incremental total daily production of 9872 STB/D was achieved in the overall optimisation projects with infill horizontal well drilling producing the highest incremental recovery. The internal rate of return for the overall project was 72% and a payback period of 3.4 years. The lessons learned, and recommendations for future development of the field were established.
Petroleum Geochemistry of the Loperot-1 Well in Lokichar Basin, Kenya
Authors: Katithi David M. , Opar David O.
Published: February 2021

The work reports an in-depth review of bulk and molecular geochemical data to determine the organic richness, kerogen type and thermal maturity of the Lokhone and the stratigraphically deeper Loperot shales of the Lokichar basin encountered in the Loperot-1 well. Oil-source rock correlation was also done to determine the source rocks’ likelihood as the source of oil samples obtained from the well. A combination of literature and geochemical data analyses show that both shales have good to excellent potential in terms of organic and hydrogen richness to act as conventional petroleum source rocks. The Lokhone shales have TOC values of 1.2% to 17.0% (average 5.16%) and are predominantly type I/II organic matter with HI values in the range of 116.3 – 897.2 mg/g TOC. The Lokhone source rocks were deposited in a lacustrine depositional environment in episodically oxic-dysoxic bottom waters with periodic anoxic conditions and have Tmax values in addition to biomarker signatures typical of organic matter in the mid-mature to mature stage with respect to hydrocarbon generation and immature for gas generation with Ro values of 0.51 – 0.64%. The Loperot shales were shown to be possibly highly mature type II/III source rocks with TOC values of 0.98% – 3.18% (average 2.4%), HI of 87 – 115 mg/g TOC and Ro of 1.16 – 1.33%. The Lokhone shale correlate well with the Loperot-1 well oils and hence is proposed as the principal source rock for the oils in the Lokichar basin. Although both source rocks have good organic richness to act as shale gas plays, they are insufficiently mature to act as shale gas targets but this does not preclude their potential deeper in the basin where sufficient gas window maturities might have been attained. The Lokhone shales provide a prospective shale oil play if the reservoir suitability to hydraulic fracturing can be defined. A basin wide study of the source rocks thickness, potential, maturation and expulsion histories in the Lokichar basin is recommended to better understand the present-day distribution of petroleum in the basin.
Research on the Tectonic Evolution of the North Africa from Morocco to Libya as the Controlling Factor on the petroleum basins’ Hydrocarbon Accumulation
Authors: Liping Xiong , Yanli Liu , Danni Shi
Published: February 2021

This paper focuses on the tectonic evolution of the North African petroleum basins as the controlling factors on the major basins’ formation, evolution and the hydrocarbon accumulation, analyzing the petroleum enrichment conditions and proposing hydrocarbon accumulation mode. The analysis concludes that the distribution of North Africa Basins is in regular east-west direction, clear depression associates with highland structure. The basins becomes gradually older from the west to the east, corresponding to the Western Paleozoic basin, the Middle part Paleozoic and Mesozoic superimposed basin and the Eastern Mesozoic-Cenozoic rift basin. Petroleum in the Middle-West basins is mainly controlled by western Hercynian tectonic movement with obvious NE – SW distribution character, while petroleum in the East basins controlled by the Alpine tectonic movement, showing NW-SE distribution. Experienced a number of north-south direction reversals, the Paleozoic basin developed in the South and the Mesozoic-Cenozoic superimposed basin overlaying the Paleozoic Basin located in the North. The basins have two different accumulation models, which are younger source rocks associated with the older reservoirs and the older source rocks with the younger reservoirs.
A Review of the Leading Technologies that Can Make a Difference in the Search for and Production of Hydrocarbons
Authors: Engelder Terry , Zhou Yaneng
Published: February 2021

As industry evolves in the 21st Century in Africa, there are fundamental questions that are in the best interest of industry to solve in exploration for and production of new prospects and in the revitalization of partially depleted fields. Many of these questions may be addressed using technologies that have evolved during the gas shale revolution of the past decade. This talk will review some of these leading technologies in briefly discussing the following ten questions. What is the state of stress in basins? What information comes from a microseismic survey? How does knowledge of a depositional environment guide the placement of a lateral? How do natural fractures evolve in shales? What information is available when sonic logging is coupled with conventional logs? Where does water go when injected into shale? What are the major subsurface structures that can be detected in multichannel seismic? How does a project deal with the smaller scale (sub-seismic) structures? How is organic carbon distributed in reservoir rock? What are the mechanisms for the development of overpressure in basins?
Slim-hole Drilling – De-risking Exploration in Remote Locations
Authors: Soquar Emmanuel , van der Westhuyzen Chris
Published: February 2021

Onshore exploration – both oil and gas and geothermal – typically involves the mobilisation of full sized conventional rigs. The support package includes back up and auxiliary parts, capable of drilling and fully evaluating deep large diameter conventional holes. In early stage exploration programs conducted in remote and frontier locations, the operating costs can approximate those of an offshore operation. This standard approach may be an unnecessary expense and lessons can be learned from the mining industry, which has been operating in a lower cost environment in frontier locations for over 125 years. A slim well approach is adopted not just to the well design but to team size, civil works, evaluation requirements and logistics. A smaller rig capable of drilling slim wells to the desired terminal depth (of up to 4,000 m), with complete logging and core sampling, can provide exploration companies with a cost effective solution.
Regionally Connected Structural Systems: The Power of the Big (Continental-Scale) Picture
Authors: Granath James , Dickson William
Published: February 2021

Beyond offshore West Africa where modern densely-sampled data from ships and satellites have played a key role in current understanding of passive margin evolution, Africa is in general rather unevenly known, especially in the subsurface in more remote areas.  The GIS-based Exploration Fabric of Africa (EFA, the ‘Purdy project’) was designed to address that problem. It includes structural features such as faults and basin outlines but at a very high and often generalized level, divorced from their underlying genetic linkages.  We have undertaken to compile a more detailed tectonic synthesis aimed to integrate understanding of the oceanic margins with the continental realm.  This is an overlay to EFA with a variety of public domain, published, non-exclusive, and derivatives of proprietary work at a closer and more detailed level, importantly guided by known patterns of structural styles.  Potential field (gravity and magnetic) data provide guidance in locating, extending, and connecting key mapped features; we then rely on the kinematic patterns to predict missing details in a testable interpretation.  The result is a detailed structural features map that can function as a framework within which to target and prioritize both conventional and unconventional activity by operators and licensing/regulatory organizations.  We illustrate the process in theory and in practice along the Central African Rift System (CARS), where data is sparse.   This fault linkage systems approach has flagged underexplored areas where unmapped structure is likely that could, for example, be targeted with hi-resolution geophysical data.  A similar system to CARS appears to cross southern Africa from Namibia to Tanzania – a “Southern Trans-African Rift system" or STARS.  Exploration in the eastern Owambo Basin resulted in the mapping of a pull-apart basin from depth-to-basement inversion of high-resolution magnetic data and subsequently studied with structural modeling.  Thinking in terms of such fault and structural systems, this ‘Kavango Basin’ can be related along strike to the Karoo Basins in Eastern Africa via features such as the Omaruru lineament, implying the possibility of a fairway of extensional basins and shears across the continent that are not obvious in existing low-resolution data. STARS represents a blue-sky frontier concept for both conventional and nonconventional exploration potentially offering new exploration leads, the ultimate objective of big picture work.
Increasing Plug and Abandon Efficiency in East Africa: Challenges and Solutions
Authors: Joneja Galen , Awalt Michael , Johnson Carl , Bogaerts Martijn , Alsam MHD Tareq
Published: February 2021

In line with an escalation of drilling operations in East Africa, operators and service contractors are increasing their focus on how to make operations more efficient in challenging market. One operation for which a robust, safe, and effective tool was utilized to increase efficiency is the plug and abandonment of deepwater exploration wells in Tanzania and Kenya.

Traditional abandonment of a well is accomplished by stacking multiple cement plugs to achieve zonal isolation. The plugs covering reservoir sections are normally independently verified in keeping with best practices applicable to well barriers. By setting longer plugs to cover multiple zones, rig time and operating costs can be significantly reduced. However, there are limitations to cement plug length when set conventionally without significantly increasing the risk of stuck pipe. The Hydraulic Tubing Release Tool (HTRT) was introduced during a deep-water exploration campaign in East Africa. It has been used successfully during the abandonment of five different wells where seven plug and abandonment operations placed long abandonment plugs, ranging from 405m to 1787m, in a single operation.

The utilization of the tubing release tool system in well abandonment operations has proved to lower the risks and operational costs through the reduction of necessary cementing operations. With the sacrificial tubing being left in the cement, there is less risk of plug contamination which occurs as a result of pulling out of the plug. It also allows for longer plugs to be set in a single operation as opposed to stacking several cement plugs to get the required length, saving additional time.

It has been used successfully on five deepwater wells in East Africa to set long abandonment plugs in open holes ranging from 700m to 1800m MD. The main objective of the disconnect system is to shorten the time taken to perform a well abandonment program as well as reducing the associated risks, thereby saving rig time and money.
Comoros – New Evidence and Arguments for Continental Crust
Authors: Milsom John , Roach Phil , Toland Chris , Riaroh Don , Budden Chris , Houmadi Naoildine
Published: February 2021

As part of an ongoing exploration effort, approximately 4000 line-km of seismic data have recently been acquired and interpreted within the Comoros Exclusive Economic Zone (EEZ). Magnetic and gravity values were recorded along the seismic lines and have been integrated with pre-existing regional data. The combined data sets provide new constraints on the nature of the crust beneath the West Somali Basin (WSB), which was created when Africa broke away from Gondwanaland and began to move north.

Despite the absence of clear sea-floor spreading magnetic anomalies or gravity anomalies defining a fracture zone pattern, the crust beneath the WSB has been generally assumed to be oceanic, based largely on regional reconstructions. However, inappropriate use of regional magnetic data has led to conclusions being drawn that are not supported by evidence. The identification of the exact location of the continent-ocean boundary (COB) is less simple than would at first sight appear and, in particular, recent studies have cast doubt on a direct correlation between the COB and the Davie Fracture Zone (DFZ). The new high-quality reflection seismic data have imaged fault patterns east of the DFZ more consistent with extended continental crust, and the accompanying gravity and magnetic surveys have shown that the crust in this area is considerably thicker than normal oceanic and that linear magnetic anomalies typical of sea-floor spreading are absent.

Rifting in the basin was probably initiated in Karoo times but the generation of new oceanic crust may have been delayed until about 154 Ma, when there was a switch in extension direction from NW-SE to N-S. From then until about 120 Ma relative movement between Africa and Madagascar was accommodated by extension in the West Somali and Mozambique basins and transform motion along the DFZ that linked them.

A new understanding of the WSB can be achieved by taking note of newly-emerging concepts and new data from adjacent areas. The better-studied Mozambique Basin, where comprehensive recent surveys have revealed an unexpectedly complex spreading history, may provide important analogues for some stages in WSB evolution. At the same time the importance of wide continent-ocean transition zones marked by the presence of hyper-extended continental crust has become widely recognised. We make use of these new insights in explaining the anomalous results from the southern WSB and in assessing the prospectivity of the Comoros EEZ.
High Expansion Technology Opens the Way for Enhanced Recovery
Authors: Masson Graham
Published: February 2021

The objective of this paper is to examine the recent improvements in High Expansion packer and plug design, while minimizing packer element extrusion. Changes that provide operators with more intervention options at reduced risk.

For thirty or more years, extrusion gap has been controlled primarily by the use of a "Gauge Ring" as a packer back up. While successful, this approach dictates a large OD packer or plug to minimize extrusion gap. As our industry has developed more tortuous wellbore geometry, large ODs have led to running and pulling problems. These designs have also prevented many operators from recovering failed zones. Water encroachment, gas migration and failed sand screens have often been dealt with by re-completion. Options were limited to inflatable systems, long elastomer or umbrella-type plugs. Horizontal completions further reduced that to only Inflatable solutions, due to umbrella systems dependency on cement. Recent developments in High Expansion products have opened up new opportunities to recover from these types of problems.

High expansion elastomers and new design packer back-up systems allow for actual V-Rated packer, plug and straddle systems. With this benefit comes the added value of a retrievable system.
The Role of Neo-Tectonics in Oil Migration, Lake Turkana Region, Kenya
Authors: Witte Jan , Trümpy Daniel , Babies Hans Georg
Published: February 2021

Numerous oil seeps have been documented in the Turkana Basin, western Kenya. However, no commercial oil has been found here to date. Recently discovered substantial oil fields in the nearby Lokichar Basin indicate that oil migration can be complex in these rift basins and may pose an exploration risk. We present a new fault and lineament map of the Turkana-Lokichar Basins, integrated with present-day stress data, oil seeps and known prospects.

Digital terrain data, satellite images, geological maps, seep and gravity data were integrated into a GIS-database, to superimpose the data and to test it for spatial correlations. Digital terrain data, satellite images, gravity and structural maps were used to conduct detailed mapping of the fault and lineament network. The seep and prospect maps are based on the integration of different public data sources.

Four main fault sets are recognized in the basin (~N-S, W-E, NW-SE and SW-NE). Careful analysis of topographic data along both shores of Lake Turkana reveals numerous fault scarps, indicative of recent tectonic activity (particularly the N-S and NW-SE set). The area is presently under NW-SE oriented extension, implying that most of the rift-parallel N-S faults are under oblique dextral transtension. The majority of the documented oil seeps and slicks are found to be associated with rift-parallel faults but also occasionally with the W-E trending set. Recently published neo-tectonic and isostatic uplift data indicate that the highest level of recent fault activity is presently found close to the rift axis and dominantly on the rift-parallel fault sets.

We conclude that ~N-S and W-E oriented faults are the most conductive pathways for hydrocarbons in this region under the present-day stress field (and likely throughout the Mio-Pliocene). We further observe that several prospects of the NW-SE trend have seepages associated with them, which could be indicative of breached traps, especially close to the rift axis where faults are most active. Our assessment should help to better understand migration pathways and exploration risks in the Turkana Basin. We encourage explorers to carefully map fault networks, investigate active fault scarps, age-date them where possible, test them for spatial correlation with oil seeps and evaluate them within the context of the present-day stress field. In consequence these workflows will help mitigate exploration risks in the Turkana-Lokichar Basins and similar tectonic settings.
Diversification of Africa's Energy Portfolio': Economic Outlook a Case Study of Kenya
Authors: Lutta Nelson
Published: February 2021

Despite the global setbacks, in recent times Africa's economy has generally managed to grow, with an average GDP increase of about 5%. Africa's economic growth prospects have been the talking point in recent economic fora. This growth however, has been inhibited due to the insufficient access to reliable electricity for most of Africa. The future outlook for this yet looks set to change dramatically, with African countries diversifying their energy portfolio. A good case in point is in Kenya. As of March 2015, Kenya's effective installed electricity capacity was 2177.1 MW, with supply primarily being sourced from hydroelectric and thermal sources. With connectivity to the national grid at just 28%. As of 8th June 2016, Kenya was the 4th largest geothermal energy developer in the world, possessing the largest geothermal plant in the world, capable of providing almost 20% of the nation's total power capacity (280MW Olkaria plant). Geothermal is just the tip of the iceberg, for years wind energy has contributed just 5.1MW to the national grid, but with the construction of the lake Turkana power project set to come online by July 2017 injecting 310MW or about 18% of current installed electricity generating capacity, a different ball game is about to commence.

With Kenya's innovation and IT scene making waves worldwide, the incorporation of this into the energy scene has been quite successful with the M-Kopa model the latest crown jewel. Solar century and London distillers have held engagements to build the largest solar roof project in East Africa, almost 1 MWp. Kenya is currently the world leader in number of solar power systems installed per capita. With the Lamu coal power plant set to add 981.5 MW to the grid and Kenya aiming to replace some fossil fuel, electricity capacity, with nuclear energy (it is currently evaluating its grid system before considering the generation options).

These are key stepping stones for an energy boom with an unequivocal industrial and economic boom. Considering the major infrastructural projects of rail, road and pipeline being undertaken with these energy prospects, the future is only brighter. The fact that most of the developed world economies are slowing down only serves to fuel the fact that Kenya and Africa's economic revolution is inevitable. A key indication that the next decades belong to Africa, at least from an economic stand point.
What Will it Take to Commercialize Petroleum Resources in the East Africa Region; The Case of Developing Oil Refinery in Uganda
Authors: Abeinomugisha Dozith , Batebe Irene , Ariho Benjamin
Published: February 2021

Energy is one of the key drivers of economic growth and development world over. Overcoming energy poverty is one of world's great challenges. All the countries in the East African Region (EAR) are not producing sufficient energy to meet their current needs.

The energy mix in the EAR currently includes hydroelectric power, geothermal energy, solar, biomass and fossil fuels. The region's petroleum products consumption, the entire volume of which is currently imported, is estimated at 180,000 bbl/day and is growing at between 4 – 6% p.a. It is projected that the region will consume about 400,000bbl/day by 2030.

The discovery of commercially viable oil and gas deposits in Uganda, Kenya, Tanzania and Democratic Republic of Congo however, marks a great opportunity to turn around the rather bleak state of the energy sector in the region. These resources however remain largely untapped due to lack of the necessary infrastructure such as road networks, upstream facilities, refinery, pipelines, and gas processing facilities, that are necessary to access, store, process and transport these resources.

A number of countries in the EAR are planning for the development of such key infrastructure to enable the commercialization of the discovered these resources. The EAR needs to harmonise the planning and development of petroleum infrastructure in order to leverage the power of collaborative action to attract investment and ensure optimal development of this infrastructure.

A case in point is Uganda which plans to commercialise its discovered oil and gas resources, estimated at 6.5 billion barrels as of 2016, through the development of an oil refinery, a crude oil export pipeline and power generation. These projects are being developed with joint participation of the East African Community (EAC) Partner States.

Uganda estimates to spend over USD 10 billion on oil and gas infrastructure in the next five years. The region needs to provide a conducive investment environment in order to attract financing for these projects. This can be achieved through providing incentives such as attractive taxation regimes, streamlined decision making and security, among others, given the high CAPEX investments. Given that background, this paper will; Assess the current status of the oil and gas infrastructure in the region vis a vis the growing energy needsDiscuss the optimal infrastructure requirements for the successful development of the oil and gas industry in order to meet the region's growing energy needs.Highlight the investment requirements, incentives, challenges and financing options for the planned refinery in Uganda.
Drill Cuttings and Fluid Disposal; A Kenyan Case Study
Authors: Lilian Simiyu E. , Esther Mburu , Allan Rukunga
Published: February 2021

The objective of this research paper was to explore the health, safety, sustainability and social responsibility during disposal of cutting and drilling fluids in Kenya in regard to what affects the choice of method of disposal, the Kenyan government's regulatory requirements on disposal of the drilling wastes, methods of addressing drilling wastes, ways of reducing the volume of wastes, hierarchy of drilling wastes and the pros and cons of various methods of addressing drilling wastes. A comprehensive case study of the approach taken in Kenya with regard to handling of drilling wastes was done. Description for each approach used is provided as obtained through interviews, internet and questionnaires and statistics. Complete tables and graphs are provided and the methods are described in detail to permit readers to understand all results. The choice of method of disposal is determined and affected largely by the government policy and also by economic, technical and operation conditions and barriers. Methods of disposal included injection, thermal treatment, bioremediation, land application. This paper gives the best ways of disposal. A comprehensive description of the Kenyan government regulations is given as indicated in the Kenya Gazette, NEMA and UNEP. This paper gives insight to the acceptable drilling wastes disposal practices in Kenya and are also generally largely applicable other nations. In conclusion, it was found that Kenya would benefit from passing its own laws to regulate disposal in the coming days.
Solar Power for Sustainable Offshore Petroleum Exploration and Production in Africa
Authors: Tawiah Samuel , Marfo Solomon Adjei , Benah Daniel
Published: February 2021

A substantial percentage of Africa's upstream petroleum activity occurs offshore in high risk environments with attendant environmental concerns. Power demands on offshore rigs are met principally through the use of diesel engines and gas turbines. This adds to the already high safety hazards and environmental threat through greenhouse gas emissions, heat and noise generation. Additionally, petroleum generated power is an expensive venture that can have significant impact on oil and gas project economics. Moreover, some of these offshore locations are so remote that accessibility to petroleum fuel may be challenging. As petroleum exploration and production pushes steadily into deeper, farther waters especially in sub-Saharan Africa, safety, environmental and logistical security may be key for sustainability. Situated almost entirely within the tropics, Africa is a very suitable place for solar energy applications. This study assesses the potential of solar power for offshore oil and gas operations in Africa to mitigate the issues associated with the use of fossil fuel thereby ensuring sustainability of the upstream petroleum industry in Africa. The size of the solar power system that may meet the power requirement of a sample floating storage and production vessel (FPSO) in offshore Angola was estimated. Appropriate areas and extent of potential solar power application on this sample rig were also assessed. This was followed by some cost analysis to compare the two sources of power economically. It was found that solar power can currently provide only a small part of the power needed on offshore rigs primarily due to lack of space and weight restrictions.
Shale Oil and Gas in East Africa (Esp.Tanzania) with New Ideas on Reserves and Possible Synergies with Renewables
Authors: Duyverman Henk J. , Msaky Emma
Published: February 2021

Short Abstract

Shale oil and gas in East Africa, with new ideas on reserves and possible synergies with renewables

Shale oil and gas production have lately revolutionized the oil and gas industry as a real "game-changer", especially in the US.

This has prompted many companies and governments to search for these unconventionals with successes in the UK, Poland and Argentina. These unconventionals do often occur onshore in places, where there is no conventional hydrocarbon production, thus enabling the local government or companies to have a new energy source, which is especially valid in Onshore East Africa.

New drilling technologies, which combine shale and geothermal drilling/production, are now being developed. Now it is possible to drill/produce both unconventionals and geothermal from a single well.Gas and oil could be produced from the central pipe, and hot water from the outer tubing, thereby reducing development cost for both methods.

In Tanzania a study was performed to look at unconventional oil and gas resources in sedimentary basins. A lot of data on Karoo geology, maturity, TOC's and volumetrics will be presented. In general, one needs a thick sedimentary basin with a lot of shales, good maturity and TOC values, and a fairly unfaulted basin to prevent seismicity when fracking. In East Africa and Southern Africa at large only the Karoo sediments of Permian/Triassic age are a suitable candidate for large shale oil/gas reserves. The possible large Karoo shale gas development in South Africa is a good example.

A large heavy oilfield at surface in Madagascar proves an oil source in the Karoo. In S.Kenya and also on Pemba oil shows are known, with a unknown Pre-Jurassic source.

Preliminary resource calculations in Tanzania indicate possible resources in place of 50-200 Tcf of gas for the Selous basin, comparable in size with the South-African Karoo Basin. The depth of the source rocks make gas the most likely hydrocarbon phase. One has to note that calculating unconventional resources is much more complicated than with conventional resources, since the adsorbed gas (or oil) needs to be calculated from core or log analyses. An onshore well could also text the synergies with geothermal drilling.

Recently, TPDC in Tanzania has started a new evaluation, based on new mapping, rock analyses and maturity studies, into the shale oil and gas potential.

Altogether, shale gas (or oil) could be an interesting incentive for onshore Tanzania and East Africa at large.
Early-Stage Extension in the Southwest East African Rift: Integration of New Seismic Reflection Data
Authors: Scholz Christopher A. , Wood Douglas
Published: February 2021

The western branch of the East African Rift is characterized by modest amounts of extension and by deeply-subsided, fault-controlled basins filled with large, deep lakes. Lakes Tanganyika and Nyasa (Malawi) are two of the largest lakes in the world, with maximum water depths of 1450 and 700 m respectively. Newly acquired seismic reflection data, along with newly reprocessed legacy data reveal thick sedimentary sections, in excess of 5 km in some localities. The 1980's vintage legacy data from Project PROBE have been reprocessed through pre-stack depth migration in Lake Tanganyika, and similar reprocessing of legacy data from Lake Nyasa (Malawi) is underway. New high-fold and large-source commercial data have recently been collected in southern Lake Tanganyika, and new academic data have been acquired in the northern and central basins of Lake Nyasa (Malawi) as part of the 2015 SEGMeNT project. In the case of Lake Tanganyika, new data indicate the presence of older sediment packages that underlie previously identified "pre-rift" basement (the "Nyanja Event"). These episodes of sedimentation and extension may substantially predate the modern lake. These deep stratal reflections are absent in many localites, possibly on account of attenuation of the acoustic signal. However in one area of southern Lake Tanganyika, the newly-observed deep strata extend axially for ~70 km, likely representing deposits from a discrete paleolake. The high-amplitude Nyanja Event is interpreted as the onset of late-Cenozoic rifting, and the changing character of the overlying depositional sequences reflects increasing relief in the rift valley, as well as the variability of fluvial inputs, and the intermittent connectivity of upstream lake catchments. Earlier Tanganyika sequences are dominated by shallow lake and fluvial-lacustrine facies, whereas later sequences are characterized by extensive gravity flow deposition in deep water, and pronounced erosion and incision in shallow water depths and on littoral platforms. The age and provenance of the sub-Nyanja Event sequences is unknown, but may correlate to Miocene, Cretaceous or Karroo-age sedimentary packages documented elsewhere in the southwestern part of the East African Rift, including in the region around Lakes Rukwa and Nyasa (Malawi).
Structure, Stoichiometry, and Modelling of Mixed Calcium Magnesium Phosphonate Scale Inhibitor Complexes for Application in Precipitation Squeeze Processes
Authors: Shaw S.S. , Sorbie K.S.
Published: February 2021

In this paper, the properties of precipitated “mixed” calcium and magnesium phosphonate scale inhibitor (SI) complexes formed by 9 common phosphonate species are investigated. These complexes are of the form SI_ CaNl _MgN2 where the stoichiometry (Ca2+/SI and Mg2+/SI molar ratios, i.e. N1 and N2) in various precipitates are established experimentally, and the effect of solution pH on the stoichiometry is determined. Static precipitation tests were performed varying the amounts of Ca2+ and Mg2+ present in the system (at a constant ionic strength), at test temperatures ranging from 20°C to 95°C, at a fixed [SI] = 2, 000ppm. The stoichiometries of the solid precipitates were determined by assaying for Ca2+, Mg2+, and P in the supernatant liquid, under each test condition, by ICP spectroscopy. It is shown experimentally that, for all 9 phosphonates tested, these stoichiometries (i.e. N1 and N2 in SI_ CaN1 _MgN2) depend on (i) the nature of the SI (i.e. M2+ binding sites per molecule); (ii) solution pH, which affects the speciation of the SI; (iii) the relative magnitude of the SI binding constants to Ca2+ and Mg2+ at the test pH (Kb1 and Kb2, respectively); and (iv) the solution molar ratio of Mg2+/Ca2+. It is found that, as pH increases, the combined molar ratio of Ca2+ and Mg2+ to SI, i.e. Nt = N1 + N2 in the complex, increases up to a theoretical maximum, Nt,max, depending on the chemical structure of the phosphonate (corroborating earlier work, SPE 155114, SPE 164051). In addition, the precipitation behaviour of the various compounds is modelled theoretically by developing and solving a set of simplified equilibrium equations. Very good agreement is seen between the modelling and experimental results. Such models can be used directly in the simulation of field phosphonate precipitation squeeze treatments in order to design and optimize squeeze lifetimes.
Experimental and Modeling Study on Enhancement of Squeeze Treatment in Sandstone by the Addition of Zinc Ion
Authors: Yan Fei , Kan Amy T. , Yan Chao , Wang Lu , Liu Ya , Tomson Mason B.
Published: February 2021

Scale inhibitor squeeze treatment is often used to control mineral scales in the oilfield. However, the performance of scale inhibitor squeeze treatment is sometimes not satisfactory due to low inhibitor retention in the formation and a short squeeze life. It has been previously found that the addition of transition metal ions increased the retention of phosphonate and carboxylate polymeric inhibitor in carbonate formation. In this study, laboratory squeeze experiments were conducted to evaluate squeeze treatment by the addition of metal ions (zinc) in Berea sandstone and oil field core materials. Several scale inhibitors including phosphonate, phosphinopolycarboxylic acid (PPCA), and phosphonated carboxylate polymer were investigated, and these scale inhibitors were mixed with metal ions in the inhibitor pill for squeeze application. Experimental results demonstrated that zinc ions in the inhibitor pills improved retention of scale inhibitors and increased squeeze life significantly. It is proposed that the metal-inhibitor precipitate or complex formed, and the formation of the precipitate/complex enhances the adsorption of scale inhibitor in the mineral matrix. It was also found that chemical composition of the mineral may have an impact on the performance of squeeze treatment, and high concentration of iron may limit the effectiveness of this treatment. The demonstration of metal ions to improve scale inhibitor squeeze will have significant implications on scale control in the oilfield.
Calcium Naphthenates in Complex Production Systems - Evaluation and Chemical Inhibition Challenges
Authors: Nichols D.A. , Rosário F.F. , Bezerra M.C.M. , Gorringe S.E. , Williams H.L. , Graham G.M.
Published: February 2021

Over the last 15 years, much research and many field application studies have led to considerable improvement in our understanding of the formation and mitigation of calcium naphthenate deposits.

In this field example, calcium naphthenates and stable emulsions are formed following mixing of fluids from different reservoir formations on a single FPSO. High TAN crudes containing low levels of ARN produce with low calcium formation waters whereas low TAN crudes are associated with high calcium formation waters. Mixing of these two systems has led to calcium naphthenate deposition and associated problems with its removal.

This paper outlines the challenges in this complex deepwater subsea production system and the interpretation of the cause of the deposit. A series of laboratory tests using a specialised flow rig were conducted to illustrate the effects of mixing different fluids and identify those mixtures with the largest naphthenate potential.

The work further illustrates the effect of bicarbonate ions on the system. Laboratory tests at low levels of bicarbonate (to prevent carbonate scaling at separator conditions) do not result in calcium naphthenate formation when mixing the high TAN crude with the current produced brine (moderate calcium). Naphthenates only formed when mixing with the high calcium brine. When bicarbonate is included at full field levels (in the presence of a scale inhibitor) significant calcium naphthenate formation is recorded with the lower calcium brines. The effect of CO2 within the produced fluids has also been evaluated.

The paper describes how several variables contribute to the likelihood of calcium naphthenate deposition and presents results from several naphthenate formation and inhibition tests covering a range of fluid compositions and mixtures. Chemical qualification in the lab using the worst case fluid mixtures has been conducted to select a calcium naphthenate inhibitor for field deployment. Field trials demonstrate both the effectiveness of the treatments and also the qualification exercise conducted for this field.

The results further indicate the complexity of accurately predicting a calcium naphthenate risk while illustrating that, even under challenging conditions, chemical inhibitors are effective in this system.
Field Method for Determination of Bicarbonate Alkalinity
Authors: Wang Lu , Kan Amy T. , Zhang Zhang , Yan Fei , Liu Ya , Dai Zhaoyi , Tomson Mason B.
Published: February 2021

Alkalinity is used to calculate the bicarbonate concentrations under various production conditions and the bicarbonate concentration is needed to calculate saturation indices for the prediction of carbonate and sulfide scale formation and also to predict the corrosivity of the produced water during production. Since the saturation index is related to the square of the bicarbonate concentration, the accuracy of alkalinity is vitally important for the prediction of corrosion and scaling indices of all oil and gas production systems. Unfortunately, the total alkalinity remains one of the most difficult parameters to be measured accurately in produced water due to both interferences and the difficulty in preserving the sample during storage. When collected samples de-gas during transport, the dissolved CO2 concentration decreases, pH increases, and brine components start to react with O2 and these reactions cause a reduction in bicarbonate alkalinity.

In this study, an experimental method was developed to determine bicarbonate alkalinity in minimal time and operating difficulty. The apparatus consists of four parts: a low pressure sealing vessel, high accuracy pressure gauge, a syringe for acid addition and a thermometer. The changed pressure in this closed vessel, which indicates the amount of CO2 evolved after the addition of a strong acid, is used to determine the bicarbonate alkalinity of the sample. A wide range of synthetic waters and two production water samples were tested. Excellent agreement has been observed between true and calculated concentration. The results enable a more accurate measurement of produced water composition without the error caused by collection and preservation of samples. The field method combined with our automatic titration method enables more accurate prediction of pH, saturation index and corrosion risk at typical conditions of deep water production.

This paper provides a reliable and detailed approach for field test of bicarbonate alkalinity with high accuracy and precision and a set of recommendations for field use.
The Influence of Turbulence (or Hydrodynamic Effects) on Strontium Sulphate Scale Formation and Inhibitor Performance
Authors: Johnston Clare , Sutherland Louise
Published: February 2021

Inorganic scale (carbonate, sulphate and sulphides) formation can be predicted from thermodynamic models and over recent years better kinetic data has improved the prediction of such scales in field conditions. However these models have not been able to predict the observed deposition where flow disturbances occur, such as at chokes, tubing joints, gas lift valves and safety valves. This can lead to unexpected failures of critical equipment such as downhole safety valves (DHSV’s), and operational issues such as failure to access the well for coiled tubing operations due to tubing restrictions.

In recent years it has been recognised that the turbulence found at these locations increases the likelihood of scale formation and experiments have been able to demonstrate that increased turbulence also impacts the minimum scale inhibitor concentration required to prevent scale.

One of the industry standard test methods used to screen inhibitors for sulphate scale inhibition is the static bottle test. In this paper the ‘static’ bottle test method is modified to investigate the effects of increasing levels of turbulence on the formation of strontium sulphate scale at a fixed brine composition. Using this modified method it has been possible to demonstrate the impact of varying turbulence on the performance of two common generic types of scale inhibitor (phosphonate and vinyl sulphonate co-polymer). Data on the mass of scale formed, scale morphology using SEM imaging and inhibitor efficiency will be linked to degree of turbulence and scale inhibitor functionality (nucleation inhibition vs. crystal growth retardation). This study builds on the previously published10 findings for barium sulphate which showed phosphonates were less affected by turbulent conditions by carrying out similar tests on strontium sulphate. A clear mechanistic conclusion can now be drawn for sulphate scale formation and inhibition under increasingly turbulent conditions.

The findings from this study have a significant impact on the methods of screening scale inhibitors for field application that should be utilised and development of suitable inhibitors that perform better under higher shear conditions.
Carbon Nanotubes: A New Methodology for Enhanced Squeeze Lifetime CNTs
Authors: Ghorbani N. , Wilson M. C. , Kapur N. , Fleming N. , Neville A.
Published: February 2021

A new potential application of nanotechnology for mineral scale prevention in the oil and gas industry is presented. In current squeeze treatments, in which scale inhibitors are squeezed into wells to adsorb or precipitate onto rock surfaces for later release, a large proportion of the injected inhibitor does not adsorb and is therefore returned very quickly from the reservoir upon well re-start. Here it is demonstrated that nano-particles have the potential to enhance squeeze lifetime by greatly increasing the adsorption of inhibitors within the formation. An extensive literature review is presented, exploring the potential for using nano-scale materials in squeeze treatments. One of the observations from scale inhibitor squeezes into sandstone reservoirs is the apparent lack of suitable surfaces available for adsorption. The main constituent of sandstones, quartz, has a very low ability to adsorb inhibitor (1 mg/l). Given this, research using nanotechnology was targeted towards enhancing the available sites for scale inhibitor adsorption within the near wellbore. Specifically, research was undertaken to examine the potential benefits of using carbon nanotubes in a process called Nanotechnology Assisted Squeeze Treatment (NAST). The process involves carbon nanotubes adsorbing and permanently modifying the near wellbore with scale inhibitors subsequently adsorbing onto the nanotubes. This process was observed to be significantly higher than a non-modified near wellbore surface, with a maximum adsorption of more than 85 and 160mg/g onto the nanotubes in solution of distilled water (DW) and CaCl2 in DW; respectively, compared to 1 mg/g directly onto the rock. Coreflood tests comparing the NAST procedure with a simplified standard coreflood show the potential for improvement of the squeeze lifetime.
Influence of Calcium and Bicarbonate Ions on the Kinetics of CaCO3 Formation at High Temperature in the Absence and Presence of Scale Inhibitors
Authors: Xu Bo , Chen Tao , Chen Ping , Montgomerie Harry , Hagen Thomas , Guo Qi , Yang Xu
Published: February 2021

The calcium and bicarbonate ions, present in the produced waters in the oilfields, are two major scaling ions in CaCO3 formation. In the last decade, a lot of studies have been focused on the thermodynamic or kinetics of CaCO3 formation, including the effects of scaling ions, temperature, pH, pCO2, etc. Seldom studies are focused on the kinetics of calcium carbonate surface deposition with different levels of calcium and bicarbonate, especially in the presence of scale inhibitors.

In the work reported herein, dynamic loop tests were carried out to study the kinetics of CaCO3surface deposition in three typical produced waters (Water-1, high calcium and low bicarbonate; Water-2, medium calcium and medium bicarbonate; Water-3, low calcium and high bicarbonate) with same saturation index (SI) at 150°C. Typical scale inhibitor chemistries, including phosphonate, polycarboxylic, polymaleic, polysulphonate, polyacrylic, polyaspartate based scale inhibitors, have been tested in three tested waters.

The following conclusions are drawn based on the test results.

SI generated by applied prediction software is a parameter indicating the thermodynamic driving force. The kinetics of scale formation, more representative field conditions, should be studied as well to give a guideline of scale formation in the fields. Comparison of calcium, bicarbonate is the dominant kinetic factor for CaCO3 formation in the absence and presence of inhibitors. Higher bicarbonate water, higher minimum inhibitor concentration (MIC) is requested, even the three tested waters with a same SI. The ranking of the performance of scale inhibitor are dependent on the water chemistries and inhibitor chemistries. Some of the best ranking phosphonates in Water-1 and Water-2 with low and medium bicarbonate showed poor performance on Water-3 with high bicarbonate. Some polymers showed contrary ranking performance.

This paper gives a comprehensive study of the kinetics of CaCO3surface deposition considering the effects of calcium and bicarbonate, including prediction, laboratory evaluation, mechanisms and inhibitor selection. It will contribute to understand the kinetics of CaCO3 formation and recommend effective inhibitors for field application. Environmentally acceptable inhibitors have been developed for different CaCO3 water chemistries at elevated temperature and are suitable for applications through squeeze treatment or continuous injection.