Не разобравшись в геологическом строении территории компания решает бурить по методу wildcat

5.1.4 Optimum nozzle and flow rate selection

The well that is studied in the field case is vertical and classified as a wildcat well. The problem to be addressed is the design of the hydraulics for the 12¼″ section in the interval 1200–3200 m. A PDC bit was chosen to drill this section. This bit had one center nozzle and five nozzles between the blades.

Criterion “New B” was chosen for the operation, mainly because the flow rate was above the critical flow for cuttings transport, 2520 L/min. From Fig. 5.6, we also see that the flow rate should ideally vary from 3250 L/min at 1200 m to 2580 L/min at 3200 m, with about 2880 L/min at 2200 m. The classical criteria recommend a lower flow rate. The data for “New B” are summarized in Table 5.5.

The result of the bit run was 1238 m drilled, which was a company record with this particular bit type. No nozzle plugging was observed. Although this field case is not proof for the new models presented here, it shows that sound preplanning does give results. In this case, two changes were introduced: a higher flow rate in the whole system and an increased flow rate in the center nozzle of the bit.

The three lines of Fig. 5.6 define the depth levels 1200, 2200, and 3200 m. As the well deepens, the parasitic pressure loss increases due to the added drill pipe. To avoid exceeding the maximum pump pressure of 290 bar, the flow rate has to be gradually decreased. From Table 5.5 and the New B criterion, we see that the proposed flow rate is 3250 L/min at 1200 m depth, decreasing to 2580 L/min at 3200 m. During an actual drilling operation, the flow rate will gradually be reduced by monitoring the pump pressure.

The actual nozzle selection process will be demonstrated using the following example:

In a practical application, we have to consider the penetration length of each drill bit, as we can only change nozzles when pulling the drill bit. If we assume one drill bit for each of the intervals of Table 5.6, five ¹³/₃₂″ and one ¹⁶/₃₂″nozzles may be used in the interval 1200–2200 m. However, since we are approaching the critical flow rate for cuttings transport in the bottom interval, we will recommend using the nozzles designed for a 3200 m depth.

If more or fewer bit runs are expected, the nozzle selection must be evaluated accordingly.

2.1 Exploration

Exploring for oil and gas reserves consists mainly of geophysical testing and drilling exploratory or “wildcat” wells to verify the existence and economic viability of the reservoir. To find crude oil or natural gas reserves, geologists typically search for a sedimentary basin in which shales rich in organic material have been buried for a sufficiently long time for petroleum to have formed. The petroleum must also have had an opportunity to migrate into porous traps that are capable of holding a large amount of fluid or gas. The occurrence of crude oil or gas is limited both by these conditions, which must be met simultaneously, and by the time span of tens of millions to hundreds of millions of years. Surface mapping of outcrops of sedimentary beds makes possible the interpretation of subsurface features, which can then be supplemented with information obtained by drilling into the crust and retrieving cores or samples of the rock layers encountered.

Ultimately, the only way to prove that oil is present underground is to drill an exploratory well. Most of the oil provinces in the world have initially been identified by the presence of surface seeps and most of the actual reservoirs have been discovered by so-called wildcatters who relied perhaps as much on intuition as on science. The term wildcatter comes from west Texas, United States, where in the early 1920s, drilling crews came across many wildcats as they cleared locations for exploratory wells. The hunted wildcats were hung on the oil derricks, and wells became known as wildcat wells. A wildcat well is essentially considered a test boring to verify the existence and commercial quantities of quality oil and gas deposits. Since the absolute characteristics of a wildcat well are unknown until actually drilled, a high-pressure volatile hydrocarbon reservoir may be easily encountered. As drilling occurs deeper into the Earth, the effects of overburden pressure of any fluid in the wellbore increases. If these reservoirs are not adequately controlled during exploratory drilling, by monitoring the pressure and use of drilling mud and fluids as counterweights, they can lead to an uncontrolled release of hydrocarbons up through the drilling system. This is commonly termed as a “blowout,” whether it is ignited or not. Blowout preventers (BOPs), that is, fast-acting hydraulic shear rams located at the surface where the pipe exits the ground, are provided to control and prevent a blowout event by immediately trapping the pressure in the pipe when activated. Uncontrolled hydrostatic pressure is considered the primary cause of drilling blowouts (while evidently the underlying root cause is human error, due to less than adequate control of the drilling operation). Since well blowouts are considered catastrophic incidents, the location chosen for exploratory wells requires careful planning and risk assessments to ensure fire, explosion, and toxic gas effects from such an event would not impact adjacent land uses (e.g., highly populated areas) or if so, and allowed by local regulatory agencies, suitable additional emergency features (e.g., perimeter gas detection/alarms, contingency plans, and drills) and procedures are in place, as defined by the risk assessment to lower the consequences to an acceptable level.

Exploratory wells that may still prove to be uneconomical have to be plugged and abandoned (commonly referred to as P&A). These activities have to be carefully completed to avoid later leaks or seepages. A few wells that were not property plugged from early drilling periods had a separate concern of small children falling into the wellsite borehole. Where these incidents occurred it resulted in dramatic rescues and unfavorable publicity for the industry.

An oil field may comprise more than one reservoir, that is, more than one single continuous, bounded accumulation of oil. Indeed, several reservoirs may exist at various depths, actually stacked one above the other, isolated by intervening shales and impervious rock strata. Such reservoirs may vary in size from a few meters in thickness to several hundred or more. Most of the oil that has been discovered and exploited in the world has been found in a few relatively large reservoirs. In the United States, for example, 60 of the approximately 10,000 oil fields have accounted for half of the productive capacity and reserves in the country.

1 General Characteristics of Oil and Natural Gas Exploration

A romantic image of exploration is one of hardy drillers risking fortunes on the luck of a wildcat well. The large risks and the financial dangers are still very much a part of modern exploration, but all the tools of modern technology are coupled with the strengths of business analysis to quantify and diminish the risks of exploration.

Exploration accomplishments come with high costs and high risks. Some idea of the risk of exploration investments, relative to other investments, may be gained by understanding that banks do not loan money for exploration investments. Hardy investors in exploration oil and gas projects are effectively lenders-of-last-resort, and such investors demand the potential for high returns to balance the exceptional risks. When a company drills a $20 million “dry hole,” a well that fails to find significant oil or gas, there is no salvage value and no optional use for the dry hole: It is a $20 million loss.

In a typical year, approximately 10 billion barrels of oil and 70 trillion cubic feet of natural gas are discovered in the world. Assuming a value of $25 per barrel for oil and $3.00 for 1000 cubic feet of gas, it can be seen that $460 billion dollars worth of new assets are discovered each year by oil and gas exploration. The rewards for exploration success can be huge, but costs are high and failure is common.

The exploration task is far greater than discovering new subsurface reservoirs of hydrocarbons; it must be that of discovering those hydrocarbons in an economically efficient manner. Successful oil and gas exploration owes as much to efficient business practices as to technical excellence.

The first step in exploration is always an innovative idea about where oil or gas might be found. The pioneering geologist Wallace Pratt once said, “Oil is first found in the minds of men.” It is hoped that such ideas arise from fundamental knowledge of the rock layers in the earth, their suitability for generating and retaining oil and gas accumulations, and an analysis of the clues available to suggest that proper conditions are actually present in a particular area. Oil and gas accumulations in the earth are extremely valuable. The discovery of new accumulations (fields) generates great wealth. Oil and gas fields are very difficult to find, and exploration—a systematic search for new oil and gas accumulations—depends on proper use of technology, acquisition of new data, and the deductive analysis of earth clues in a manner reminiscent of a detective.

2 Fundamental Concepts

“Proved reserves” are estimated quantities of hydrocarbons that geologic and engineering data demonstrate with reasonable certainty to be recoverable from identified fields under existing economic and operating conditions. Estimates of proved reserves are important because they are the leading indicators of short-term sustainability of oil and gas production. No more than 10 to 15% of proved reserves (and often much less) can be extracted annually to avoid reservoir damage. So proved reserve levels limit annual production to amounts well short of known recoverable resources.

The objective of oil and gas exploration is to identify resources that can be added to proved reserves. These resources should be of such a quality and quantity that the resource can be commercially developed immediately. Industry exploration consists of a variety of activities that include surveying of surface geology, processing and interpreting newly collected geophysical data, reprocessing and interpreting previously collected data, acquiring mineral rights and access, taking subsurface core samples, and finally drilling exploratory oil and gas wells.

Exploration wells drilled to find reserves are classified by risk level. Categories for exploration wells are extension or outpost wells, new pool tests (shallower or deeper pool), and new field wildcat wells. Even the standard infill development well is not without risk; some development wells are drilled that fail to make contact with the producing reservoir. Risk, or the probability of failure, on average tends to increase from infill development wells to exploratory wells represented by extensions and outposts, new pool tests, and then to new field wildcat wells. Historically, an exploratory well is classified as a new field wildcat well when it is drilled at least two miles from the nearest productive accumulation. Other exploratory wells that find reserves through new pool tests and extension drilling commonly add reserves to fields already discovered.

Estimates of sizes of oil and gas fields are commonly based on known recovery. A field’s known recovery is defined as the sum of its past production and most recent estimate of proved reserves. When additions to proved reserves are credited to a field already discovered, its field size based on the estimate of known recovery is said to grow. Resource analysts call hydrocarbon resources that are expected to be added to the proved reserves of discovered fields inferred reserves. The movement of known hydrocarbon resources from the inferred to proved reserve category commonly requires exploratory drilling.

There may be some ambiguity whether new reserves are classified as either from new fields or from field growth (see Fig. 1). The U.S. Department of Energy defines a field as an area consisting of a single or multiple reservoirs all related to the same individual geologic structural feature and/or stratigraphic condition. There may be two or more reservoirs in the field that may be separated vertically or laterally by impermeable strata. From a practical standpoint, the definition of an oil or gas field is not exact. The assignment of pools to fields may be for convenience in regulation, or it may be an artifact of the discovery sequence of the pools, rather than for well-defined geologic reasons. Depending on the time sequence of discovery, accumulations shown in Fig. 1 may be assigned to a single field or to more than one field.

Continuous-type hydrocarbon accumulations commonly have reservoir properties that impede the flow of hydrocarbon fluids. Most of these accumulations require that extra measures be taken to induce additional flow to the well bore in order to attain commercial production rates. These measures may include drilling wells with horizontal sections or fracturing the formation to create passageways for the resource to migrate to the well bore. Unconventional or continuous-type gas accumulations have received increasing attention by the U.S. domestic petroleum industry during the past decade. Basin-centered gas accumulations (Fig. 2) may be partially developed by the recompletion and stimulation of wells that have depleted shallower conventional pools. If new wells target the continuous-type accumulation, the drilling risk is dominated by failure to stimulate or complete the well so that commercial flow-rates are attained, rather than by missing hydrocarbon-charged sedimentary rocks. Most of the wells drilled in continuous-type accumulations are classified as development wells. In this article, only exploration for conventional discrete accumulations is discussed.

Outside of the United States and Canada, oil and gas exploration is still directed to discrete conventional accumulations. Nonetheless the in situ hydrocarbon resources in the continuous-type accumulations are substantial, and the costs incurred in drilling and producing such resources provide a backstop or upper bound to the costs that should be incurred in finding and developing discrete conventional accumulations.

4.4.23 Qasr al Ahrar Formation

In northern Cyrenaica Upper Cretaceous rocks are attributable to either a platform facies (in the south and west), or a basinal facies (in the north and east), with some interfingering in the transition zone. The oldest Cretaceous rocks are exposed in a small inlier at Qasr al Ahrar (formerly Jardas al Abid), near the site of the first wildcat well in Libya, Al-18, where a deeply eroded anticline exposes rocks of Cenomanian age. The geology of this inlier was described by Kleinsmeide and van den Berg, Pietersz, and Barr. The oldest sequence exposed in the inlier was named the Jardas al Abid Formation, but following renaming of the village is now called the Qasr al Ahrar Formation. It was re-examined during the remapping for the Geological Map of Libya. The outcrop shows the top of a sequence of green and yellow ochreous marls with thin marly limestones. Only about 10m is exposed at outcrop, but a further 200m was penetrated in the Al-18 well. A description was given by Hawat and Shelmani. The formation contains a rich fauna of planktonic foraminifera, pelecypods and ostracods which indicate a late Cenomanian age. The formation has been penetrated in several wells in northern Cyrenaica, and in offshore well Al-NC 120 the Qasr al Ahrar Formation unconformably overlies the Albian Daryanah Formation. (Figure 4.11). Here the formation represents a regressive cycle, passing from open-marine conditions to restricted lagoonal conditions at the top. Nearshore marine limestones containing early Cenomanian palynomorphs have also been reported from wells Al-28, Al-19, Ala-117, Al-NC 92 and Bl-2.¹²⁴

Oilfield development

There are three main stages in the establishment and exploitation of an oil or gas field. The first step is to carry out a seismic survey to identify rock structures that could be oil bearing. Offshore, this was at first done by detonating a propane-oxygen mixture in a rubber container and analysing the reflections from the sub-sea strata. An alternative source is a high-energy vibrator. Explosives are no longer used because of the damage caused to marine life.

When a likely area is found its boundaries are determined and then an exploratory vertical well is drilled somewhere close to the centre. This is the wildcat well and is generally considered to be the most hazardous of the drilling operations, because the composition and pressure of any hydrocarbon that may be present is unknown. If results from the first well are positive, other exploratory wells are drilled with the object of defining the extent of the field.

In the third phase an offshore field is developed by establishing fixed platforms and using these as a base to drill production wells. Sometimes there will be only a single vertical well; more often multiple wells are sunk.

1.3 Exploration Activity, 1956 to 1958

The first wildcats to be drilled in Libya under the new Petroleum Law were located mostly on structures identified by surface mapping. Libyan American spudded well Al-18 in April 1956, only four months after the licence was granted.¹² The well tested a large anticlinal structure in northern Cyrenaica which proved to be dry. In 1957 four companies were involved in drilling campaigns. Libyan American drilled two more dry holes on concession 18, and BP drilled a dry hole in the area near Tripoli investigated by Agip before the war. Esso began operations in concession 1 close to the recent French discoveries in Algeria. Their second well made a gas discovery which, on appraisal, turned out to be a significant find containing both oil and gas in multiple reservoirs. Mobildrilled the first well in the Sirt Basin, Al-57, which was drilled primarily to evaluate the Cainozoic section on the Az Zahrah Platform, but proved to be dry.¹³

Drilling began in earnest in 1958. Twenty-eight wildcat wells were spudded and the first major discoveries were made. In west Libya Esso continued to evaluate concession 1 with six further wells, several of which had gas shows, and Shell began evaluating the area north of concession 1. Gulf drilled three dry holes in concession 67 on the edge of the Murzuq sand sea, and tested oil in well A1-68 in an area where major discoveries were to be made in later years. CFP made a small oil discovery in Devonian sandstones at Tahara in concession 49, and Shell made the first discovery in the northern Ghadamis Basin at Tlakshin in the Akakus reservoir of late Silurian age. Further east BP drilled two wells in the area between west Libya and the Sirt Basin without success.¹⁴

Drilling continued in the Sirt Basin and in April 1958 the first undoubted commercial discovery was made when the Al-32 well of Oasis discovered the Bahi field which contained oil in Palaeocene carbonates in a gentle low-relief structure on the western margin of the Az Zahrah Platform. This was followed in September by a much larger discovery in the B1-32 well which Oasis named the Az Zahrah (Dahra) field. On the adjacent block Mobil drilled the Al-11 well which encountered good shows in the same reservoir interval, and which on appraisal, proved another major discovery, which Mobil named the Al Hufrah (Hofra) field. Amoseas was active on the western flank of the Sirt Basin, but without success. Esso began operations in the central Sirt Basin and reported a small discovery in Eocene carbonates in concession 5.¹⁵ The 1958 drilling programme had resulted in seven discoveries of which three were commercial (Bahi, Az Zahrah and Al Hufrah).

12 Summary

Offshore operations cover a broad range of activities that include exploration, exploration drilling, development drilling, production, workover, and transportation. Offshore exploration includes the use of seismic surveys. Seismic survey methods yield evidence of the presence of hydrocarbons in formations that lie below the oceans and seas of the world. Should exploration reveal the likelihood of hydrocarbons at a certain site, then drilling a well becomes necessary. Often, operators use a mobile offshore drilling unit—a MODU—to drill the well. Because companies can evaluate a well after they drill it, they can find out for sure whether oil and gas reside in a potential reservoir. Evaluation techniques such as logging, drill stem testing, and coring can confirm that the exploration well has penetrated a hydrocarbon-bearing formation.

If the wildcat well shows what appear to be ample quantities of oil and gas, a company may drill appraisal wells. Appraisal wells further confirm that the reservoir holds enough hydrocarbons to justify the enormous expense of developing the reservoir. If commercial amounts of oil or gas do exist in a reservoir, the company must develop the reservoir. It may move a self-contained platform to the site and erect the platform. The platform may be a rigid steel or concrete structure. Usually, the operator drills several development wells from the platform. On the other hand, the operator may place a subsea template on the seafloor, and drill the wells from a MODU. Whether from a platform or on a template, the operator drills and completes several wells to produce hydrocarbons from the reservoir.

Producers may drill satellite wells where they cannot get to the reservoir from a platform or a template. Satellite wells and wells drilled on a template are often subsea completions—that is, producers install the Christmas trees on or below the seafloor. Wells that operators complete on platforms are usually surface completions: they install the Christmas trees on a platform deck above the waterline.

The production phase of offshore operations includes the installation of special pieces of equipment to separate and treat crude oil, natural gas, and water. In most cases, operators install the equipment on a platform—usually the same platform they drilled the wells on. Sometimes, however, they install the equipment on a special processing and storage ship. They most often use such ships with subsea completions.

Operating companies may have to put wells produced from platforms and from special ships on artificial lift. They will most likely use gas lift, which allows wells to produce after natural drive depletes. In some cases, applying additional recovery techniques to extract still more hydrocarbons from an aged and dying reservoir may be possible.

Once a company completes and puts development wells on production, it will need to service and repair the wells to keep them producing at the desired rate. In many instances, operators can use wireline and pumpdown repair methods, but in other instances, they may have to move in a semisubmersible or jackup well service and workover unit.

Finally, a company may build a pipeline to transport the oil and gas to refineries or plants for the extraction of useful products. Or perhaps tanker ships will shuttle oil to shore. If so, the operator will install special mooring systems. Offshore operations occur all over the world because it is beneath the oceans and seas where the petroleum industry will find most of the world’s future hydrocarbons.

2.1 Introduction

Iodine has been detected in some of the oilfield brines, and iodine has been determined quantitatively in one sample and found to amount to 29 ppm in the Sunset-Midway oilfield (United States). In 1894 in one of the old Jewett and Blodgett wells in the Sunset field, 19.8 ppm of iodine in water was reported. Also, it has been stated waters from several other wells gave a “strong reaction” to iodine [1]. It was identified in 1910 that all the waters in the Romanian oilfields contained high amounts of iodine and that the iodine content in waters in nonoil-bearing regions was very low or nil [2]. Therefore the presence of iodine in the water was been evaluated as an direct indicator of the presence of oil. Iodine content of fossil seawater released during the burial of petroliferous sediments is higher than normal seawater; thus it identified that as the cause of a local high iodine concentration in the basin of high iodine content oilfield waters [3]. Exploration in the petroliferous Pannonian basin containing the giant Algyo gasfield was triggered by the Hajduszoboszlo-1 well drilled as a first partly successful wildcat well in 1924–1925 years. The well has produced hot (73°C), iodine-rich water at a rate of 1600 L/minute and methane gas at a rate of 3700 m³/day from a depth of 1090 m. The iodine-rich waters eventually turned Hajduszoboszlo into a health spa and the methane gas has been used locally to generate electricity [4]. It has been stated that a vast amount of iodine found in waters is originates from petroleum, and, iodine is a direct hydrogeochemical indicator for petroleum [5]. Many studies have proven the relationship between petroleum and iodine-rich waters in hydrocarbon production basins [2,6–18]. Iodine has been used to discover an oil or gasfield in many studies [13,19–34].

The relationship between petroleum and iodine in formation waters of 243 production wells in 52 oilfields which have different geological structures in the Southeastern Anatolia and Thrace Basins (Turkey) has been examined (accounting for more than 95% of oil and gas production of Turkey). It has been stated that the all of oil reservoir waters in the Southeastern Anatolia and Thrace basins are not saline. However, all of them are rich in iodine like in other oil- and gas-production fields/basins of the world. It has been stated that the iodine content of reservoir waters and oilfield reserves (petroleum saturation) is high in the basin with source rocks containing high organic matter (kerogen). In this case, the water saturation of the production wells will decrease. Also, it has been stated that the iodine-rich waters are a direct indicator determining the potential producible oil reservoirs (containing mature hydrocarbons) in the Southeastern Anatolia is a direct indicator [18].