Reservoir Engineering

Up till now, there has not been one specific correlation published to directly estimate the bubblepoint pressure in the absence of PVT analysis and, at the moment, there is just one published correlation available to estimate the bubblepoint oil FVF directly in the absence of PVT analysis. The majority of the published bubblepoint pressure and bubblepoint oil FVF correlations cannot be applied directly. This is because the correlations require the knowledge of bubblepoint solution GOR and gas specific gravity as part of the input variables, both of which are rarely measured field parameters. Solution GOR and gas specific gravity can be obtained either experimentally or estimated from correlations. In this study, multiple regression analysis technique is applied in order to develop two novel correlations with which to estimate the bubblepoint pressure and the bubblepoint oil FVF. These new correlations can be applied in a straightforward manner by using direct field data. Additional correlations or experimental analyses are unnecessary. Separator GOR, separator pressure, stock-tank oil gravity and reservoir temperature are the only key parameters required to predict bubblepoint pressure and bubblepoint oil FVF using the proposed correlations.

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In the oil province of southern Iran like other hydrocarbon zones, thorough understanding and risk management resulting from the rock mass deformation, can be of great help in executing operational processes such as the stabilization of the borehole wall, controlling the sand production in the borehole and hydraulic fracture. In oil well excavation operations, determining maximum and minimum horizontal stresses helps in designing the excavation route in the minimum stress direction so that collapsing of the borehole wall and drilling tube blockage against the rocks is avoided. The aim of this study was removing the main excavation problems especially of the diversion wells through exact geomechanical calculations in the Darian lime formation depth range in the understudy field. In order to develop the geomechanical model, first the bulk, the shear and the Young's modules, the Poisson coefficient and Vp/Vs ratio were calculated using the visual log data integrated with the geomec...

An optimized completion design that addresses gaps in the existing single well Producer-Injector (P-I) concept is presented in this paper. Field development scenarios based on the optimized P-I concept and conventional waterflood were implemented in full-field 3D simulation models.

Detailed review of the existing single P-I well concept revealed gaps in the completion design with regards to feasibility of data acquisition, ease of well intervention and well safety/control. The existing design utilizes a Single-String-Single (SSS) design with through-tubing water injection and oil production through annulus, whilst the optimized design is a Two-String-Dual (TSD) incorporating the flexibility of independent injection/production, zonal isolation for interventions & data acquisition and additional safety completion jewelries.

A fit-for-purpose reservoir candidate was selected by assessing it’s suitability to waterflooding. The reservoir belongs to the paralic sequence of the Agbada Formation of the Niger Delta basin - a sequence of interbedded sandstones and shales. The reservoir is an elongated anticline bounded by W-E oriented faults and exhibiting channelized shoreface sediments. Porosity and permeability ranges are 17-31% and 200mD-2200mD respectively. Shale baffles strongly reduces the influence of the aquifer hence the simulation model is an oil reservoir with weak aquifer completed by the P-I well producing oil and injecting into the aquifer in tandem. Performance of the single P-I well strategy was benchmarked against conventional waterflood patterns to effectively capture the recovery efficiency and production forecast for each scenario.

Results from the five-parameter experimental design based on the P-I strategy, indicate Ultimate Oil Recovery is most impacted by horizontal permeability; injection rate, flow barrier transmissibility and vertical permeability with the least influence. Dynamic 3D water saturation maps show the waterflood front propagating principally in the horizontal direction from the injector, providing important reservoir boundary pressure support and minimizing the chance for injected water short-circuiting at the sandface.

Ultimate Oil Recovery of 5spot/line drive patterns and the P-I strategy were similar, 54% and 52% respectively. Well completion costs and forecasts were fed into simple economics spreadsheet to test which technique provides the most value. Open book economics results showed the P-I concept provides better value (NPV 23.0 and VIR 0.67) than 5 spot and line drive patterns (NPV -17 and VIR -0.14).

In the oil province of southern Iran like other hydrocarbon zones, thorough understanding and risk management resulting from the rock mass deformation, can be of great help in executing operational processes such as the stabilization of the borehole wall, controlling the sand production in the borehole and hydraulic fracture. In oil well excavation operations, determining maximum and minimum horizontal stresses helps in designing the excavation route in the minimum stress direction so that collapsing of the borehole wall and drilling tube blockage against the rocks is avoided. The aim of this study was removing the main excavation problems especially of the diversion wells through exact geomechanical calculations in the Darian lime formation depth range in the understudy field. In order to develop the geomechanical model, first the bulk, the shear and the Young's modules, the Poisson coefficient and Vp/Vs ratio were calculated using the visual log data integrated with the geomec...

Reservoir characterization and structural mapping using integration of well logs and 3-D seismic data was carried out to determine the prolificacy of OVU field, onshore Niger delta. The distribution of reservoir physical parameters (porosity, permeability etc.) and availability of traps that favour hydrocarbon accumulation in the field were evaluated. Four hydrocarbon bearing reservoirs were delineated out of several identified sands in the field out of which three horizons were mapped. Two major growth faults, an antithetic fault and five synthetic faults were delineated. Structural closures were identified as rollover anticlines with the trapping mechanism delineated as a Fault assisted anticlinal structure. The computed range of values for gross thickness, volume of shale, net to gross, water saturation, hydrocarbon saturation, total porosity and absolute permeability with respect to each reservoir are: 18-125m, 9-17%, 83-92%, 18-28%, 62-82%, 21-23%, and 736-3965mD respectively. Hydrocarbon reserves calculations reveals a total reserve of 30.9 billion stock tank barrels of oil. With the very good to excellent calculated values of petrophysical parameters and high hydrocarbon reserve together with the suitable trapping mechanisms makes the study field prolific. Few wells exist in the southwestern corner of the field where a closure is identified in this study. The area should therefore be subjected to further evaluation with a view to increasing the number of wells there.

Uncertainty analysis is a critical component of field development plan which describes the risks and assists to achieve comprehensive understanding of reservoir characteristics. Accurately assessing and ranking key uncertainties provides necessary tools to the technical and management team to mitigate risks appropriately and generate robust development scenarios over the range of key uncertainties. Uncertainty in input parameters impacts the project in two ways—in-place volumes and recovery factor. In this study, an analysis methodology is adopted in such a way to assess the impact of uncertainty on both independently.

The Gulf of Suez in Egypt has a north-northwest–south-southeast
orientation and is located at the junction of the African and Arabian
plates where it separates the northeast African continent from the
Sinai Peninsula. It has excellent hydrocarbon potential, with the
prospective sedimentary basin area measuring approximately
19,000 km2, and it is considered as the most prolific oil province
rift basin in Africa and the Middle East. This basin contains more
than 80 oil fields, with reserves ranging from 1350 to less than 1
million bbl, in reservoirs of Precambrian to Quaternary age. The
lithostratigraphic units in the Gulf of Suez can be subdivided into
three megasequences: a prerift succession (pre-Miocene or Paleozoic–
Eocene), a synrift succession (Oligocene–Miocene), and a
postrift succession (post-Miocene or Pliocene–Holocene). These
units vary in lithology, thickness, areal distribution, depositional
environment, and hydrocarbon importance. Geological and geophysical
data show that the northern and central Gulf of Suez consist
of several narrow, elongated depositional troughs, whereas the
southern part is dominated by a tilt-block terrane, containing numerous
offset linear highs.
Major prerift and synrift source rocks have potential to yield oil
and/or gas and are mature enough in the deep kitchens to generate
hydrocarbons. Geochemical parameters, sterane distribution, and
biomarker correlations are consistent with oils generated from marine
source rocks. Oils in the Gulf of Suez were sourced from potential
source rock intervals in the prerift succession that are typically
oil prone (type I), and in places oil and gas prone (type II), or
are composites of more than one type (multiple types I, II, or III
for oil prone, oil and gas prone, or gas prone, respectively).
The reservoirs can be classified into prerift reservoirs, such as
the Precambrian granitic rocks, Paleozoic–Cretaceous Nubian sandstones,
Upper Cretaceous Nezzazat sandstones and the fractured
Eocene Thebes limestone; and synrift reservoirs, such the Miocene
sandstones and carbonates of the Nukhul, Rudeis, Kareem, and Belayim
formations and the sandstones of South Gharib, Zeit, andpost-Zeit. The majority of oil fields in the region incorporate
multiple productive reservoirs. Miocene
evaporites are the ultimate hydrocarbon seals, whereas
the shale and dense limestones of the prerift and the
synrift stratigraphic units are the primary seals. Structural,
stratigraphic, and combination traps are encountered
in the study area. The Gulf of Suez is the most
prolific and prospective oil province in Egypt, and any
open acreage, or relinquished area, will be of great interest
to the oil industry.

The Pelana Field is a mature waterflood field in the Central Sumatera Basin that consists of multi-layer sands with contrasted properties. Waterflood has been applied since 1997, targeting all producing reservoirs. These layering reservoirs are challenging in achieving a good alignment in term of waterflood optimization. In multi-layer injectors, such a condition will lead to bad vertical distribution of injection, where the poorest quality sand receives the least water injected.

This is a problem occurring in some injectors in the Pelana Field, where the injection is not evenly distributed vertically so that the topmost reservoir, which also has the poorest quality with permeability of around 100 mD, does not receive enough injection to balance its production. Most of the injected water goes to MN_XX sand which has permeability of about 1000 md. Injector PL-55, for instance, injects into both sands to support the production from both reservoirs. However, the previous completion uses only open ended tubing and therefore, based on the spinner result, the water will be distributed naturally based on the well-to-reservoir pressure difference, being directly affected by reservoir permeability. This practice resulted in an unbalanced performance for both sands. While MN_XX has a good sweep efficiency with recovery factor (RF) increment > 8%, the BK_AA sand would has an opportunity to be optimized due to its current low incremental of RF.

Side Pocket Mandrel has been chosen to resolve the vertical distribution problem in PL-55 and improve the injection rate into BK_AA sand. It is observed that the well can finally split its injection into more desirable allocation, allowing more water to flow into BK_AA sand. This paper presents the application of this technology in PL-55 well, including the technology principles, the tool design, the strategy to improve the injection distribution and the enhanced performance to the surrounding producers.

There are primary, secondary and improved recovery methods that are developed according to the Field's needs, however, the primary recovery does not influence the increase of reservoir´s energy as the secondary and improved recovery does. Mature fields require such an increase in energy due to their production time, so water, gas or chemical injection methods also known as enhanced recovery methods (EOR) are required to satisfy the hydrocarbon demand of the moment.
This project search to quantitatively evaluate the implementation of a new enhanced recovery technology, such as the injection of silica nanoparticles, comparing it with conventional chemical recovery methods (Surfactant and Polymer) and thus determine its effectiveness and viability in the model sector of Yariguí-Cantagallo Field.

Chemical materials such as alkaline, surfactants, and polymers are widely used for the chemical EOR to reduce the trapped oil saturation in the reservoirs. Parameters such as surfactant adsorption and surfactant loss affect the performance of the mentioned EOR method. In this paper an attempt is made to enhance the performance of the surfactant flooding by application of nanoparticles. A series of core flooding tests were completed for sandstone core samples under reservoir conditions to study the effect of a novel application of nanoparticles to alter the properties of the surfactant in chemical flooding EOR processes. Sodium dodecyl sulfate (SDS) is widely used for the EOR approach. Silica nanoparticles were used to change the surfactant adsorption on the rock surfaces. The results showed that the addition of hydrophilic nanoparticles reduces the surfactant adsorption on the rock and improves the performance of the surfactant flooding which increases the oil recovery.

A practical pressure transient analysis method is presented for a drawdown test in a well near a constant pressure internal circular boundary. The problem was mathematically posed and solved using the Laplace Transformation with the Laplace solutions . Internal boundaries are viewed as circles with infinite radii and act as a known limiting case for finite radii internal boundaries. The time it takes pressure transient to reach the internal circular boundary and the permeability of the reservoir formation bounded by an internal discontinuity is estimated using generalized type curves. Using a new generalized type curve developed in this investigation, the bounded reservoir permeability and transient time to the internal boundary was determined by generalized semi-log type curve matching without using the usual double straight line technique

Urban and environmental historians are becoming increasingly interested in the social construction of expertise in the management and control of natural resources. Experts are often depicted as disinterested, neutral and objective professionals, sufficiently qualified to gauge an independent perspective on a given problem. Yet what happens when an expert's judgment is called into question by other professional experts? The micro-analysis of socio-technological disasters offers one way to interrogate the construction and challenge of professional expertise at both the empirical and conceptual levels. Taking a comparative approach towards the study of two major reservoir failures involving considerable death and destruction in the United Kingdom – Holmfirth in 1852 and Sheffield in 1864 – this paper draws on the under-utilised research of the sociologist Barry Turner and others on the social aetiology of disasters as a route into revealing and accounting for the contested nature of expertise within the Victorian engineering professions. It is based on extensive archival research, including the written records of local and central government, private waterworks' proprietors, the printed press and the records of public inquiry. The cases reveal remarkable continuities in administrative and professional knowledge regarding the explanation of socio-technological disasters, as well as the widespread use of outside experts to interrogate the supposed failings of interested parties.

Free copy available until 4 December from http://authors.elsevier.com/a/1Ps~P15XEnSlBh

Up to now, there has not been one specific correlation published to directly estimate the bubble-point pressure in the absence of pressure-volume-temperature (PVT) analysis. Presently, there is just one published correlation available to estimate the bubble-point oil formation volume factor (FVF) directly in the absence of PVT analysis. Multiple regression analysis technique is applied to develop two novel correlations to estimate the bubble-point pressure and the bubble-point oil FVF. The developed correlations can be applied in a straightforward manner by using direct field measurement data. Separator gas oil ratio, separator pressure, stock-tank oil gravity, and reservoir temperature are the only key parameters required to predict bubble-point pressure and bubble-point oil FVF.

Analysis of the effects of formation damage on the productivity of gas storage reservoirs was performed with depleted oil reservoir (OB-02), located onshore, Niger Delta, Nigeria. Information on the reservoir and the fluids from OB-02 were collected and used to evaluate the deliverabilities of the gas storage reservoir over a 10-year period of operation. The results obtained were used to plot graphs of deliverability against permeability and skin respectively. The graphs revealed that as the permeability decreased, the skin increased, and hence a decrease in deliverability of gas from the reservoir during gas withdrawal. Over the ten years of operating the reservoir for gas storage, the deliverability and permeability which were initially 2.7 MMscf/d and 50 mD, with a skin of 0.2, changed to new values of 0.88 MMscf/d and 24 mD with the skin as 4.1 at the tenth year.

The Suffolk Coast and Heaths Area of Outstanding Natural Beauty (AONB) has been designated for its special, nationally important qualities. Any development within the Area, including farm reservoirs, should respect its distinctive character, and ought to contribute towards maintaining or enhancing that character. This guide describes what can be done to conserve and enhance the AONB when planning farm reservoirs.

History matching is the recent accurate way of updating sequentially geological well data to match the model from field production data.  Apart from providing the current production results, history matching can also provide forecasting results based on predictions. By this way of reservoir simulation the historical data are matched as closely as possible. How accurately and precisely the match can be done just depends on the quality of the reservoir model and quantity of parameters. The Ensemble Kalman-Filter (EnKF) as an automatic history matching procedure has gained popularity as Monte-Carlo approach in real time reservoir simulation of continuously updated pressure and production data. The Ensemble model is being updated every time when the new data becomes available and it starts firstly with prior model to be updated to posterior model which later changes to prior model again in every step of assimilation. The main advantage is that EnKF history matching itself is eligible to update both static and dynamic properties (comparing with traditional history matching) at the same time while simulation and is entirely automated. Kalman Filter based methods perform sequentially and only update the model with the latest available data, not the whole historic data. An assimilation step is implemented to modify the model parameters, based on the difference between reservoir simulation responses and the data from the field. The article describes the main methodology of EnKF in reservoir history matching with the field case example. The usability of this method is evaluated through a discussion of its applications and benefits. The article is therefore relevant for all those interested in the use of History Matching by means of Ensemble Kalman Filtering.

A la edad de 45 años, Eduardo Juan Couture Etcheverry, el gran jurista uruguayo, impartió una conferencia en el Colegio de Abogados de Buenos Aires, reproducida en el Boletín del mismo de 1949. Tiene como génesis un esbozo publicado en la Revista de Derecho Procesal de 1948, de donde nace una pequeña obra jurídica de enorme contenido ético, quizá de los más famosos textos de la literatura en la materia, Los mandamientos del abogado, mejor conocido como El decálogo del abogado.

The well placement technology has advanced to a stage where we can explore small tolerance targets such as thin reservoirs. Well placement with geosteering, which is the real time adjustment of the well path based on the geological responses to place and maintain the well within the best part of the reservoir, is the technology that has made this progress possible. Geosteering however can get very complex with the increasing heterogeneities of the formations and there is no fixed methodology to devise a steering strategy in such complex geological settings.

Nigeria is gradually advancing into the secondary stage of oil recovery, necessitating preparation for tertiary oil recovery especially enhanced oil recovery (EOR). Considering the high cost of EOR agents, it is imperative to investigate the performance of available local EOR agents against foreign agents when these agents (such as surfactants and polymers) are used in combination. Oil displacement experiments were thus conducted using foreign and local surfactant-polymer (SP) and alkaline-polymer (AP) agents on Nigerian crude and their results were compared. The experiments entailed using different percentage ratios of surfactants to polymers and alkaline to polymer. Four kinds of Alkaline were also used to displace residual oil from sand to find out what type of alkaline displaces oil better. The displacement efficiencies obtained from experimental results showed that the foreign EOR agents performed better than the local EOR agents. For the SP agents, the foreign SP displaced above 90% of both light and medium crude at about 45/55 percentage and 0/100 percentage respectively. The local SP displaced a maximum of about 35% of the light crude and 75% of medium crude at an SP ratio of about 20/80 for both cases. The use of Alkaline-Polymer results showed that the foreign agents performed better than the local agents. The maximum displacement efficiency of the foreign AP was 78.13% at a ratio of 40/60 while the maximum displacement efficiency of the local AP was 64% at a ratio of 60/40. The displacement of residual oil experiments performed using four kinds of alkaline showed that potassium hydroxide (KOH) enhances recovery better than NaOH, Na 2 CO 3 and Palm bunch ash (a local source of alkaline). It was also observed that oil displacement efficiency increased as pH value of the alkaline increased.

Oil in place by the volumetric method is given by: Where: N(t) = oil in place at time t, STB V b = 7758 A h = bulk reservoir volume, bbl 7758 = bbl/acre-ft A = area, acres h = thickness, ft φ(p(t)) = porosity at reservoir pressure p, fraction S w (t) = water saturation at time t, fraction B o (p(t)) = oil formation volume factor at reservoir pressure p, bbl/STB p(t) = reservoir pressure at time t, psia II. Calculating Gas in Place by the Volumetric Method Gas in place by the volumetric method is given by: Where: G(t) = gas in place at time t, SCF V b = 43,560 A h = bulk reservoir volume, ft 3 43,560 = ft 3 /acre-ft A = area, acres h = thickness, ft φ(p(t)) = porosity at reservoir pressure p, fraction S w (t) = water saturation at time t, fraction B g (p(t)) = gas formation volume factor at reservoir pressure p, ft 3 /SCF p(t) = reservoir pressure at time t, psia

Many reservoir engineers are facing a major challenge in the best technique of producing very large oil reserves. Some of the common techniques employed to effect high productivity are the development and use of EOR methods and giant non-recoverable hydrocarbon resources.

The identification of fluid contacts (gas–water contact—GWC, oil–water contact—OWC and gas–oil contact—GOC) is essential for field reserve estimates and field development and, also, for detailed formation evaluation. For the accurate calculation of some petrophysical parameters, such as porosity, the reservoir interval has to be zoned by fluid type, to account for differences in fluid saturations and fluid properties (e.g., hydrogen index, density, sonic transit time) in the various intervals: gas cap, oil column and aquifer zone. The fluid contacts may vary over a reservoir either because of faults, semipermeable barriers, rock quality variations / reservoir heterogeneity, hydrocarbon-filling history or a hydrodynamic activity. Horizontal contacts are typically taken into consideration, although irregular or tilted contacts occur in some reservoirs. The methods used for determining the fluid contacts include fluid sampling, water and hydrocarbons saturation estimation from geophysical well logs, analyses of conventional or sidewall cores, and formation pressure measurements. The pressure profiles obtained with various formation testing tools over reservoir intervals are, frequently, the primary source of data for defining the fluid contacts. When good quality pressure data can be collected, the fluid contacts can be determined by identifying the depths at which the pressure gradients (pressure versus depth trends) change. This study addresses some issues related to the identification of GWC for two gas fields of Early Pliocene age (Dacian stage), belonging to the biogenic hydrocarbon system of western Black Sea basin-Romanian continental shelf. We show that the identification of these contacts based exclusively on pressure gradients analysis is uncertain or may be inaccurate. The pressure gradients approach should be checked against the results of the conventional interpretation of geophysical well logs (e.g. changes in the computed fluid saturations as a function of depth) and, if available, the results of nuclear magnetic resonance (NMR) log investigations, which are able to indicate the intervals with clay-bound water, capillary-bound water and movable fluids.

The mathematical expressions that are used to predict the volumetric performance and pressure behavior of the reservoir vary in forms and complexity depending upon the number of mobile fluids in the reservoir. There are generally three cases of flowing systems:

The second edition of Gulf publishers best selling book of 2006. This time as Elsevier-Gulf joint publication. Even though this is a basic book with time-honoured appeals, it has been revamped to help out modellers and computer program users so that they can save years of man-hours by avoiding the old-school approach.

This Paper shows how to determine the daily cost of running diesel engine to power a duplex pump in a simple and understandable way, and how to determine the cost of additional Barite required  to drill the encountered high-pressure zone using the recorded shut-in drill pipe pressure (SIDPP).

Wellbore instability is one of the key problems that engineers encounter during drilling. Often, field instances of instability are a result of a combination of both chemical and mechanical factors, the former resulting from the failure of the rock around the hole due to high stresses, low rock strength, or inappropriate drilling practice and the latter arising from damaging interactions between the rock, generally shale, and the drilling fluid. The increasing demand for wellbore stability analyses during the planning stage of a field arise from economic considerations and the increasing use of deviated, extended reach and horizontal wells, all of which are highly susceptible to the problem. This paper presents a review of the causes, symptoms, prevention, associated consequences, types and respective problems and the principle behind the problem of wellbore instability in oil well drilling.

Generally, low flow in rivers occur as a result of extended period of dryness which is likely attributed to drought. Drought is a natural occurrence as an outcome of reduction in precipitation in a region for a long time. Hence, low flow is a growing concern as there are possibilities of more reduced flows in rivers. However, reservoirs can be utilized to mitigate negative effects on the supply of water in dry periods and supply water for other purposes. This study aims at verifying how the low flow condition of Glomma River in Norway has been progressively sustained by hydropower reservoirs. Water Evaluation and Planning Systems (WEAP) software was used for modelling the natural streamflow condition of Glomma River, which is the longest river in Norway, using two unregulated sub-basins within the Glomma catchment. Findings from this study presents that the period between January and March are critical periods in Glomma River. Results show that the values the annual minimum low flow gotten from the three gauges suggest the flow after regulation has increased significantly as opposed to before regulation. The daily average flow is simulated by WEAP to be an average of 100 m 3 /s during the low flow periods and an average discharge of 350 m 3 /s during the summer. However, the result indicates that the flow in the summer has reduced by 80% in majority of the years. In addition, Nash Sutcliffe efficiency (NSE) for the two sub basins used for this study was 0.9 and 0.76, respectively. Also, the calculation of the coefficient of determination (R 2) resulted in 0.85 and 0.78 respectively for the two sub basins. In particular, findings from this study presents evidence on the low flow condition in Glomma River prior to its regulation and how the regulation has sustained the flow.

Geo-pressured gas reservoirs are reservoirs with high pressure gradient of about (0.5-1.0) psi/ft. The increase in pressures has been proposed by some authors to be caused by inability of excess fluids to leak-off after major tectonic events of compressional folding or rapid deposition of thick sediments in young sedimentary rocks. The limitation of the conventional method in estimating original gas in place (OGIP) in a geo-pressured gas reservoir is that the solution gas in connate water is habitually neglected in estimating the OGIP. As a result, its contribution of the total gas production is omitted in the MBE. This leads to an inaccurate estimation of OGIP and gas reserve. To eliminate this error, a new form of MBE is presented by this study. It includes the contribution of solution gas in connate water to the total gas production. A comprehensive compressibility term that includes the rock compressibility (Cf), water compressibility (Cw) and the gas solubility in water (Rsw) are introduced into the material balance equation and P/Z plots are formulated. The result of the formulation indicates a 5 -12% increase in the estimation of the OGIP as compared to some existing methods. This tells the importance of the solubility of gas in brine in the estimation of the OGIP and the importance of its inclusion in the Material Balance Equation.

Drill stem testing follows the basic principles of mechanics, hydromechanics, common sense and practicability. This seminar paper will present methods for the quantitative analysis of drill stem test. The drill-stem test operation is divided for discussion into three phases: planning the test, performing the test, and interpretation. This seminar paper, provides a thorough review of the technical and practical aspects of drill stem testing.

Optimasi dan pola operasi waduk/bendungan dapat digunakan dengan beberapa metode diantaranya Program linier, Program Dinamik maupun simulasi.
This writing can inform for you all, how to optimum the reservoir so can fulfill water needs irrigation in Agricultural lands.